Systems and methods for generating in-situ carbon dioxide driver gas for use in enhanced oil recovery

ABSTRACT

The present invention is an in-situ apparatus for generating carbon dioxide gas at an oil site for use in enhanced oil recovery (EOR). The apparatus includes a steam generator adapted to boil and superheat water to generate a source of superheated steam, as well as a source of essentially pure oxygen. The apparatus also includes a steam reformer adapted to react a carbonaceous material with the superheated steam and the pure oxygen, in an absence of air, to generate a driver gas comprising primarily carbon dioxide gas and hydrogen gas. A separator is adapted to separate at least a portion of the carbon dioxide gas from the rest of the driver gas to generate a carbon dioxide-rich driver gas and a hydrogen-rich fuel gas. A compressor is used for compressing the carbon dioxide-rich driver gas for use in enhanced oil recovery, and the compressed carbon dioxide-rich driver gas, with substantially no oxygen, is injected to a predetermined depth in order to enhance oil recovery at the oil site. Unlike traditional CO 2 -EOR, which requires large power plants stationed near metropolitan areas and expensive pipeline networks, the in-situ apparatus can be placed or constructed at the site of the oil field, while a portion of the carbonaceous material may be obtained from a site outside the oil field.

REFERENCE TO RELATED APPLICATIONS

This application is a Continuation-in-Part (CIP) and claims priorityfrom co-pending application U.S. Ser. No. 12/165,585, entitled “SYSTEMSFOR EXTRACTING FLUIDS FROM THE EARTH AND FOR GENERATING ELECTRICITYWITHOUT GREENHOUSE GAS EMISSIONS,” filed on Jun. 30, 2008, which itselfis a Continuation of U.S. Ser. No. 11/751,028, entitled “PORTABLE ANDMODULAR SYSTEM FOR EXTRACTING PETROLEUM AND GENERATING POWER,” filed onMay 20, 2007, and issued on Jan. 26, 2010 as U.S. Pat. No. 7,650,939,the entirety of both of which are hereby incorporated by referenceherein.

FIELD OF THE INVENTION

This invention relates to a system and method for generating in-situ CO₂from a carbonaceous feedstock for use in enhanced oil recovery. Oneembodiment of the present invention is a power plant which utilizes asteam reforming process that may be used to generate electricity,hydrogen, and high pressure carbon dioxide-rich gas which is utilizedfor EOR.

BACKGROUND OF THE INVENTION

The world's power demands are expected to rise 60% by 2030. With theworldwide total of active coal plants over 50,000 and rising, theInternational Energy Agency (IEA) estimates that fossil fuels willaccount for 85% of the energy market by 2030. Meanwhile, trillions ofdollars worth of oil remain underground in apparently “tapped-out”wells. The present invention allows much of this domestic oil to berecovered, while generating clean, distributed electric power andreducing the amount of CO₂ released into the atmosphere from combustionof coal. As both oil and clean electricity (CO₂-emmission-freeelectricity) represent products whose high value today will onlyincrease in the future, the potential profit from the present inventionis quite large.

The U.S. currently produces approximately 5.1 million barrels of oil aday. Most of the oil fields in the U.S. are declining in oil recoveryproductivity. It has been proven that using CO₂ for Enhanced OilRecovery (EOR) can increase oil recovery productivity in the decliningfields. The U.S. Department of Energy (DOE) conducted several studiesand has deemed CO₂-EOR to be the most promising solution to increase oilrecovery productivity. The DOE estimates that 100 million barrels of“stranded” oil can be recovered using CO₂-EOR.

The DOE states that “while a mature hydrocarbon province, the U.S. stillhas 400 billion barrels of undeveloped technically recoverable oilresource. Undeveloped domestic oil resources still in the ground(in-place) total 1,124 billion barrels. Of this large in-place resource,400 billion barrels is estimated to be technically recoverable. Thisresource includes undiscovered oil, “stranded” light oil amenable toCO₂-EOR technologies, unconventional oil (deep heavy oil and oil sands)and new petroleum concepts (residual oil in reservoir transition zones).The U.S. oil industry, as the leader in enhanced oil recoverytechnology, faces the challenge of further molding this technologytowards economically producing these more costly remaining domestic oilresources. Of the 582 billion barrels of oil in-place in discoveredfields, 208 billion has been already produced or proven, leaving behind374 billion barrels. A significant portion of this 374 billion barrelsis immobile or residual oil left behind (“stranded”) after applicationof conventional (primary/secondary) oil recovery technology. Withappropriate enhanced oil recovery (EOR) technologies, 100 billionbarrels of this ‘stranded’ resource may become technically recoverablefrom already discovered fields.”

There are tens of thousands of depleted oil and natural gas wells aroundthe world, which collectively possess significant amounts of petroleumresources that cannot currently be extracted using conventionalextraction techniques. For example, in a typical oil well, only about30% of the underground oil is recovered during initial drilling(“primary recovery”). An additional approximately 20% may be accessed by“secondary recovery” techniques such as water flooding. In recent years,“tertiary recovery” (also known as “Enhanced Oil Recovery,” or EOR)techniques have been developed to recover additional oil from depletedwells. Such tertiary recovery techniques include thermal recovery,chemical injection, and gas injection. Using current methods, thesetertiary techniques allow for an additional 20% or more of the oil to berecovered.

Gas injection is one of the most common EOR techniques. In particular,carbon dioxide (CO₂) injection into depleted oil wells has receivedconsiderable attention owing to its ability to mix with crude oil. Sincethe crude oil is miscible with CO₂, injection of CO₂ renders the oilsubstantially less viscous and more readily extractable.

Despite the potential advantages of CO₂ in enhanced recovery, its usehas been hampered by several factors. For instance, in order for theenhanced recovery process to be economically viable, the CO₂ gas must benaturally available in copious supplies at reasonable cost at or nearthe site of the oil well. Alternatively, CO₂ can be produced fromindustrial applications such as natural gas processing, fertilizer,ethanol and hydrogen plants where naturally occurring CO₂ reservoirs arenot available. The CO₂ must then be transported over large distances viapipeline and injected at the well site. Unfortunately, such CO₂pipelines are difficult and costly to construct.

For most oil fields, a CO₂ pipeline is not a viable option because of amix of several problems: (a) The capital investment for building apipeline—sometimes tens or hundreds of millions of dollars; (b) Thetime-frame of building a pipeline—several years; (c) The distance andterrain issues between the source and destination which either makes thepipeline impossible or simply not economical; (d) The time it takes toobtain easement rights and permits is long; and (e) The time it takes tostart generating an increase in productivity—the return on investment(ROI) is too long.

For example, Anadarko Petroleum Corporation built a 125-mile CO₂pipeline in Wyoming from an ExxonMobil gas plant to Salt Creek, Wyo., a100-year old oil field. They expect to increase production from approx.5,000 bbl/day in 2005 to approx. 30,000 bbl/day by 2010. However, theproject cost hundreds of millions of dollars, and took over 5 years ofplanning, permitting, and construction to complete. Therefore, whenfaced with the hurdles and overall costs of the pipeline-delivered CO₂,as described above, tertiary CO₂ EOR simply does not make economicalsense for most oil fields, especially small producers scattered all overthe United States and the world.

In the past, the idea of using the exhaust from fossil-fuel firedelectricity plants for EOR has been widely discussed. However, theelectrical industry, for reasons of economy of scale, has based itselfprimarily on large (500 MWe to 1000 MWe) central power stations, locatednear their primary metropolitan markets. For many reasons, includingnotably those laid out above, as well as the fact that flue gases fromconventional fossil power plants typically contain relatively low (<10%)CO₂ concentrations, such stations offer little potential utility forsupporting EOR, especially by small producers.

Another gas that can potentially be used for enhanced recovery purposesis hydrogen. However, hydrogen has received considerably less attentionthan CO₂. Hydrogen, although somewhat soluble with oil, is believed lessso than CO₂. Moreover, traditionally, hydrogen has been costly toproduce and its use has not been justified from an economic standpoint.

The rising cost of crude oil, as high as $120 to $140 per barrel in thesummer of 2008, and well over $70 per barrel in 2010 during the midst ofa large economic recession, has increased interest in new enhanced oilrecovery technologies. Simultaneously, the low cost of coal and biomass,often lower than $40 per ton, as well as the low cost of natural gas,have made carbonaceous feedstocks attractive fuel sources for EORpurposes.

Accordingly, as recognized by the present inventors, what are needed area novel method, apparatus, and system for extracting oil/petroleum fromthe ground or from oil wells, such as depleted oil wells, by utilizingdriver gases generated from a carbonaceous fuel source. What are alsoneeded are a method, apparatus, and system for extracting natural gasfrom the ground or from natural gas wells by utilizing driver gasesgenerated from a carbonaceous fuel source.

Therefore, it would be an advancement in the state of the art to providean apparatus, system, and method for generating large quantities ofcarbon dioxide, hydrogen and other gases from a carbonaceous fuel sourceat low cost at or near an oil site.

It is against this background that various embodiments of the presentinvention were developed.

BRIEF SUMMARY OF THE INVENTION

Accordingly, one embodiment of the present invention is an in-situapparatus for generating carbon dioxide gas at an oil site for use inenhanced oil recovery (EOR). The apparatus includes a steam generatoradapted to boil and superheat water to generate a source of superheatedsteam, as well as a source of essentially pure oxygen. The apparatusalso includes a steam reformer adapted to react a carbonaceous materialwith the superheated steam and the pure oxygen, in an absence of air, togenerate a driver gas comprising primarily carbon dioxide gas andhydrogen gas. A separator is adapted to separate at least a portion ofthe carbon dioxide gas from the rest of the driver gas to generate acarbon dioxide-rich driver gas and a hydrogen-rich fuel gas. Acompressor is used for compressing the carbon dioxide-rich driver gasfor use in enhanced oil recovery, and the compressed carbon dioxide-richdriver gas, with substantially no oxygen, is injected to a predetermineddepth in order to enhance oil recovery at the oil site. Unliketraditional CO2-EOR, which requires large power plants stationed nearmetropolitan areas and expensive pipeline networks, the in-situapparatus can be placed or constructed at or near the site of the oilfield, while a portion of the carbonaceous material may be obtained froma site outside the oil field.

Yet another embodiment of the present invention is the apparatusdescribed above, where the carbonaceous material is selected from thegroup consisting of coal, biomass, natural gas, crude petroleum,ethanol, methanol, and trash, and/or mixtures thereof.

Yet another embodiment of the present invention is the apparatusdescribed above, where a gas turbine is adapted to utilize a portion ofthe hydrogen-rich fuel gas to generate electricity, and waste heat fromthe gas turbine is used to provide heat needed to boil water.

Yet another embodiment of the present invention is the apparatusdescribed above, where the electricity generated has substantially lessassociated carbon dioxide emissions than electricity generated from thecombustion of the carbonaceous material, including coal and/or naturalgas.

Yet another embodiment of the present invention is the apparatusdescribed above, where the driver gas further comprises residual carbonmonoxide, and wherein the apparatus further comprises a water gas-shiftreactor disposed downstream of the steam reformer for converting theresidual carbon monoxide into additional carbon dioxide gas andadditional hydrogen gas.

Yet another embodiment of the present invention is the apparatusdescribed above, where the driver gas further comprises residual carbonmonoxide, and the apparatus further comprises a methanation reactordisposed downstream of the steam reformer for converting the residualcarbon monoxide into methane.

Yet another embodiment of the present invention is the apparatusdescribed above, further comprising a furnace adapted to utilize aportion of the hydrogen-rich fuel gas to generate heat necessary todrive the steam reformer.

Yet another embodiment of the present invention is the apparatusdescribed above, further comprising a heat exchanger disposed betweenthe steam generator and the furnace adapted to exchange heat between thehot gas exiting the furnace and the steam generated by the steamgenerator.

Yet another embodiment of the present invention is the apparatusdescribed above, further comprising a heat exchanger disposed betweenthe steam generator and the steam reformer adapted to exchange heatbetween the hot driver gas exiting the steam reformer and the steamgenerator in order to boil and superheat water into superheated (“dry”)steam.

Yet another embodiment of the present invention is the apparatusdescribed above, further comprising a condenser disposed after the heatexchanger adapted to condense and cool the driver gas before enteringthe separator.

Yet another embodiment of the present invention is the apparatusdescribed above, further comprising a heat exchanger disposed betweenthe steam reformer and the steam reformer adapted to exchange heatbetween the hot driver gas exiting the steam reformer and the steamentering the steam reformer.

Yet another embodiment of the present invention is the apparatusdescribed above, where the steam reformer operates at a temperature ofapproximately 600° C. to 1000° C. Yet another embodiment of the presentinvention is the apparatus described above, where the steam reformeroperates at a pressure of approximately 5 bar to 100 bar.

Yet another embodiment of the present invention is the apparatusdescribed above, where the CO₂ separator is a methanol-based separator.

Yet another embodiment of the present invention is the apparatusdescribed above, where the separator operates in a temperature-swingcycle between approximately −60° C. and +40° C., and a pressure-swingcycle between approximately 1 bar and 100 bar.

Yet another embodiment of the present invention is the apparatusdescribed above, further comprising a control system adapted to controlan operation of the apparatus based on a temperature, a pressure, and agas composition of the driver gas in real-time by controlling an inputoxygen-to-steam ratio.

Yet another embodiment of the present invention is the apparatusdescribed above, where the steam reformer is selected from the groupconsisting of a fixed bed reformer, a fluidized bed reformer, and anentrained-flow reformer.

Another embodiment of the present invention is a method for generatingcarbon dioxide gas at an oil field site for use in enhanced oilrecovery. The method includes the steps of providing a source ofsuperheated steam, and providing a source of essentially pure oxygen.Then, steam reforming a carbonaceous material with the superheated steamand the pure oxygen to generate a driver gas comprising primarily carbondioxide gas and hydrogen gas. Next, separating at least a portion of thecarbon dioxide gas from the driver gas to generate a carbon dioxide-richdriver gas and a hydrogen-rich fuel gas, compressing the carbondioxide-rich driver gas for use in enhanced oil recovery, and injectingthe compressed portion of the carbon dioxide-rich driver gas, withsubstantially no oxygen, to a predetermined depth in order to enhanceoil recovery at the oil site. The steam reforming reaction is performedadjacent to the oil field site and in an absence of air.

Yet another embodiment of the present invention is the method describedabove, where the carbonaceous material is selected from the groupconsisting of coal, biomass, natural gas, crude petroleum, ethanol,methanol, and trash.

Yet another embodiment of the present invention is the method describedabove, further comprising using a portion of the hydrogen-rich fuel gasto generate electricity for beneficial use on-site or transfer to anelectrical grid.

Yet another embodiment of the present invention is the method describedabove, further comprising utilizing a water gas-shift reactiondownstream of the steam reforming reaction to convert residual carbonmonoxide in the driver gas into additional carbon dioxide gas andadditional hydrogen gas.

Other features, utilities and advantages of the various embodiments ofthe invention will be apparent from the following more particulardescription of embodiments of the invention as illustrated in theaccompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A illustrates an example of an embodiment of a power plantaccording to the present invention for the reformation of super-heatedhigh-pressure steam with carbonaceous material to create a gaseousmixture rich in hydrogen and carbon dioxide gas in which the hydrogencombusts in a gas turbine for electricity generation while the carbondioxide gas is used for EOR;

FIG. 1B illustrates a sample temperature diagram illustrating transferof heat between hot driver gas exiting the steam reformer andwater/steam entering the steam reformer in order to maximize thermalefficiency according to one embodiment of the present invention;

FIG. 2 illustrates an example of operations for reforming super-heatedsteam and carbonaceous material to create a gas mixture rich in hydrogenand carbon dioxide in which the hydrogen combusts in a gas turbine forelectricity generation while the carbon dioxide gas is used for EOR;

FIG. 3 illustrates an example of an indirect fuel reformer for use witha power plant of the present invention, in accordance with a oneembodiment of the present invention;

FIG. 4 illustrates an example of an autothermal fuel reformer inaccordance with an alternative embodiment of the present invention;

FIG. 5 illustrates an example of a fixed-bed steam reformer for use witha power plant of the present invention in accordance with one embodimentof the present invention;

FIG. 6 illustrates an example of a fluidized-bed steam reformer for usewith a power plant of the present invention in accordance with analternative embodiment of the present invention;

FIG. 7 illustrates an example of a power plant utilizing a natural gasreformer according to yet another embodiment using the principles of thepresent invention;

FIG. 8 illustrates an example of a power plant utilizing a local oilreformer according to yet another embodiment using the principles of thepresent invention;

FIG. 9 illustrates how a power plant of the present invention may becomposed of one or more modules according to another embodiment of thepresent invention;

FIG. 10 illustrates an example of an embodiment of the present inventionfor the extraction of oil from an oil well;

FIG. 11 illustrates another example of an embodiment of the presentinvention for the extraction of oil from an oil well and for thegeneration of electrical power;

FIG. 12 illustrates a sample flow of CO₂ associated with an apparatusaccording to one embodiment of the present invention utilizing biomass,showing net reductions of atmospheric CO₂;

FIG. 13 illustrates an economic model comparing financial multipliersfor various fuel combinations for a system generating 250 mcf of carbondioxide per day;

FIG. 14 illustrates an economic model comparing financial multipliersfor various fuel combinations for a system generating 1,000 mcf (1 MMcf)of carbon dioxide per day; and

FIG. 15 illustrates a parametric economic model comparing financialmultipliers for various feedstock materials as a function of thehydrogen effectiveness relative to carbon dioxide effectiveness inenhancing oil recovery.

DETAILED DESCRIPTION OF THE INVENTION

This innovative power plant design utilizes efficient reformation ofcarbonaceous fuel and steam to improve upon traditional combustionmethods of fuel and air which currently dominate the power generationindustry. The reformation of carbonaceous fuel allows power plants tocontribute to the hydrogen economy by producing hydrogen for less energythan the hydrogen provides. This design also allows for sequestrationand/or beneficial use of CO₂ for a variety of applications such as therecovery of otherwise inaccessible oil, fire extinguishers, welding,pneumatic systems, biological applications, and chemical processing.

The hydrogen is either burned to produce clean electricity, to be soldto utilities or used for other uses such as a chemical production, fuelcell application, or enhanced oil recovery, depending on which of thesemethods produce higher monetary value to the operator.

If biomass is used as the fuel source, as a result of the fact that theCO₂ injected into the ground comes from biomass, whose carbon came fromthe atmosphere, the electricity generation process of the power plantdesign not only produces power without emission of CO₂ into theenvironment, it may actually reduce atmospheric CO₂. In fact, in oneembodiment, the amount of carbon sequestered in the process may be onaverage about 5-30%, and preferably 20-30%, greater than the amount ofcarbon in the oil recovered. Thus, not only the electricity, but eventhe oil produced by the enhanced oil recovery process can be said to betruly “green,” since it has been fully paid for by the carbonsequestered to get it.

Throughout this disclosure, the symbol “kcf” and “mcf” both shall standfor “thousand standard cubic feet,” usually of CO₂ unless explicitlystated otherwise. The symbol “MMcf” shall stand for “million standardcubic feet,” usually of CO₂ unless explicitly stated otherwise. That is,a reformer that produces 1 kcf/day of driver gas produces 1,000 standardcubic feet of driver gas per day, while a reformer that produces 1MMcf/day of driver gas produces 1,000,000 standard cubic feet of drivergas per day. The word “day” shall mean “a day of operations,” whichcould be an 8-hour day, a 12-hour day, a 24-hour day, or some otheramount of time.

Steam Reforming of Biomass and H₂ Used to Generate Electricity

One of many illustrative scenarios is presented here to demonstrate thepotential profitability of the reformation power plant design. In thisscenario, biomass is used as the carbonaceous material feedstock; theCO₂ produced is used for EOR, while all of the hydrogen is used forpower generation.

In the past, the idea of using the exhaust from fossil-fuel fired powerplants for EOR has been widely discussed. However, the electricalindustry, for reasons of economies of scale, has based itself primarilyon large (500 MWe to 1000 MWe) central power stations, located neartheir primary metropolitan markets. For many reasons, including notablythose laid out above, as well as the fact that flue gases fromconventional fossil power plants typically contain relatively low (<10%)CO₂ concentrations, such stations offer little potential utility forsupporting EOR, particularly for small producers.

In contrast, the current invention may be built on or taken directly tothe site of an oil field. The system is made up of three primarycomponents: steam reformer, gas separator, and gas turbine electricalgeneration system.

Steam reformation of biomass occurs approximately in accord with thefollowing reaction:

C₄H₆O₃+3H₂O+O₂→4CO₂+6H₂ ΔH=+4 kcal/mole  (1)

This reaction is nearly energetically neutral, and if carried outcompletely in accord with reaction (1), will produce a gas mixture thatis 40% CO₂. This concentration may be reduced somewhat by reverse watergas shift side reactions that may occur, or increased as a result ofmethanation reactions:

CO₂+H₂→CO+H₂O ΔH=+9 kcal/mole  (2)

CO₂+4H₂→CH₄+2H₂O ΔH=−41 kcal/mole  (3)

However, on net, a CO₂ concentration (in the gas after water knockout)approaching 40% can be achieved. This CO₂ concentration is much higherthan that available in combustion flue gas, and is very favorable forCO₂ separation. Examining equation (1), we can see that only one O₂molecule is needed for every four CO₂ molecules produced, a small ratiowhich makes the use of oxygen in place of air practical. Assuming thatone of the four CO₂ molecules produced by reaction (1) is consumed byreaction (3), and we use the extra energy to cut the oxygen input, weobtain a net reaction:

C₄H₆O₃+2H₂O+½O₂→3CO₂+CH₄+3H₂ ΔH=+18 kcal/mole  (4)

Reaction (4) is best done at high pressure, with 10 bar being adequatefor good results. Since the only gas that needs to be fed into thesystem is a small amount of oxygen (the water can be initially pressuredin the liquid phase), the required compression energy is minimal.Running reaction (4) at high pressure also has the advantage ofproducing high pressure exhaust gas, which simplifies the task ofseparating the CO₂ from the other product gases.

In experiments done to date, using a combined oxygen-steam feed (1 partoxygen to 6 parts steam by mole) reacting with charcoal at 10 bar, gasoutputs with a composition of 55% hydrogen, 2% methane, 8% CO, and 35%CO₂ have been obtained. Such high fraction CO₂ produced at pressure ismuch more susceptible to separation than the ˜10% CO₂ at 1 bar producedin ordinary combustion system flue gas. With further adjustments to thesystem, even closer approximations to the ideal yields given by equation(4) are attainable.

Carbon dioxide is approximately two orders of magnitude more soluble inmethanol than any of methane, hydrogen, nitrogen, oxygen, or carbonmonoxide. The methanol also acts as a trap, removing sulfur impuritiesfrom the gas stream. Large amounts of CO₂ absorbed at low temperatureand high pressure at one column can then be out-gassed in nearly pureform in a second column operating at low pressure and highertemperature. In experiments done to date, using a two column combinedpressure and temperature swing cycling methanol system, the inventorshave shown that at 10 bar pressure and −40° C., methanol will take in tosolution about 75 grams per liter of CO₂ from a 20% CO₂/80% N₂ gasmixture, with less than 4 grams/liter of N₂ entrained. In thedemonstrated system, product gas purities of 92% CO₂ can be obtainedfrom a 20% CO₂ feed, with 90% of the input CO₂ in the feed gas streambeing captured into the product stream. The 92% pure output CO₂ streamcan then be liquefied. In the process of liquefaction, nearly pure CO₂is obtained, which can be brought to whatever high pressure is requiredfor underground injection at little energy cost.

Let us consider the economics of an in-situ reformer power plant locatedat or near an oil field. Depending on the field, it takes between 5,000and 10,000 cubic feet of CO₂ to produce 1 barrel of oil. We adopt themore conservative number of 10,000 cubic feet/bbl. In that case, it willtake 560 metric tons of CO₂ per day to produce 1,000 barrels of oil perday. Examining reaction (4), we see that 3 CO₂ molecules with a totalmolecular weight of 132 are produced for every unit of biomass with amolecular weight of 102, for a weight ratio of about 1.3. Thus,producing 560 metric tons of CO₂ will require 430 tons of biomass.Currently, corn stover can be obtained for about $40 per ton, deliveredcost, within 50 miles. Thus, 430 tons of corn stover would go for a costof about $17,200. Other forms of crop or forestry residues, or evencoal, could potentially be obtained much cheaper, depending upon thelocality, but we will use commercially priced corn stover in ouranalysis to be conservative. This would allow the production of 1,000barrels of oil, which at a price of $60/bbl, would be worth $60,000.

However, in addition to the oil product, the system also produceselectricity. At the same time that 560 metric tons of CO₂ are produced,the power plant also produces 68 tons of methane and 25.4 tons ofhydrogen. If burned in air, these will produce 2,000 MWt-hours ofenergy. Assuming 30% efficiency, this translates into 600 MWe-hours ofpower, which at a price of $0.05/kWh, would sell for $30,000. The poweroutput of the system would be 25 MWe, which is well within the range ofmany gas turbine units produced by industry. It may be further notedthat the revenue from electricity alone significantly exceeds the costof feedstock (and other daily costs, outlined below).

Adding the $30,000 per day revenue from electricity to the $60,000earned from oil, we see that a total gross income of $90,000 per day canbe obtained at a cost of $17,200 in feedstock. Assuming labor costs of$4,000 per day and capital and depreciation costs of $4,100 per day(assuming a per unit capital cost of $15 million, paid off at 10% peryear), total daily operating costs would be $25,300. Thus the net profitof the operation would be $64,700 per day, or about $23.6 million peryear.

Therefore, using the principles taught by the present invention,profitable hydrogen production and clean electricity and oil productionmay become economically feasible.

The Long-Felt, Unsolved Need for On-Site CO₂ Production for EOR

Carbon dioxide (CO₂) flooding potential for enhanced oil recovery (EOR)has been effectively demonstrated in the U.S., particularly in thePermian Basin of west Texas and southeast New Mexico. Much of theresearch on CO₂ flooding can be applied to other gas flooding processes.Today over 350,000 BOPD (barrels of oil per day) are being produced bygas injection in the U.S.; approximately 70% of this oil, or over260,000 BOPD is from CO₂ injection projects. With present oil pricesaround $75 per barrel, this CO₂ oil production represents about $9billion less in imports each year, and provides a significant number ofdomestic jobs as well. Out of the 350 billion barrels remaining in U.S.oil reserves, the amount of oil presently produced by CO₂ floodingbarely scratches the surface of this resource. The potential recovery isat least an order of magnitude greater.

There are a number of reasons that CO₂ is not more widely used. Twosignificant reasons that are overcome by an on-site CO₂ productiontechnology are: 1) fields too small even if relatively near a majorpipeline to justify construction of a pipeline, and 2) no relatively lowcost CO₂ available.

It is a major undertaking to install a pipeline. Hindrances include theright of way, environmental impact, guarantee of long-term users,guarantee of long-term consistent source, timeliness of availability,and size of economy. A small field will unlikely justify a pipeline ofany size or distance. If CO₂ can be produced on site economically inquantities (1-10 MMCFD, millions of cubic feet per day) sufficient forone to a few dozen injection wells, CO₂-EOR would be available for anysize field. As an example of the potential in the U.S., there areseveral isolated relatively small CO₂-EOR projects developed nearindustrial sources of CO₂ (for example, the Muffin Drilling in Kansaswith one field, Core Energy in Michigan with 8 fields, and ChaparralEnergy in Oklahoma with two fields). These range in size from oneinjector to 40 injectors, with production from 3 to 1100 BOPD. Itrequires 5-10 MCF of CO₂ to increase production by about 1 BBL. Futureprojects are looking at $50-80 per BBL for oil. If the cost of CO₂ iskept under 50% of the cost of the oil, and the low-end is considered,then we are looking at <$25, or $2.50 MCF (<$45/ton), for CO₂ if weconsider 10 MCF/incremental barrel of oil.

A process that can provide CO₂ at a relatively low cost in about anyquantity required would open up about half of the oil fields in the U.S.for miscible CO₂ flooding EOR. If immiscible CO₂ flooding EOR isincluded (heavy oil and/or shallow reservoir), this would open up mostfields in the U.S. These two processes generally increase oil recoverabove conventional process 5 to 15% of the original oil in place (OOIP).

A U.S. Department of Energy (DOE) report published in February 2006,which was one of the factors that inspired the inventors to develop thistechnology, entitled “EVALUATING THE POTENTIAL FOR ‘GAME CHANGER’IMPROVEMENTS IN OIL RECOVERY EFFICIENCY FROM CO₂ ENHANCED OIL RECOVERY,”(hereinafter, “the DOE Report”), states, inter alia:

“The United States has a large and bountiful storehouse of oilresources, estimated at nearly 600 billion barrels of oil in-place inalready discovered oil fields. Currently used primary/secondary oilrecovery methods recover only about one-third of this resource, leavingbehind (“stranding”) a massive target for enhanced oil recovery.

“Important steps have been taken by industry to improve the recoveryefficiency in domestic oil reservoirs, notably in applying thermalenhanced oil recovery (TEOR) methods to the shallow, heavy oil fields ofCalifornia and CO₂-EOR to the deeper, light oil fields of West Texas. Todate, these improved oil recovery technologies have provided about 14billion barrels of domestic oil production and reserves, adding about 3percent to domestic oil recovery efficiency.

“Even including the important steps taken so far by industry, theoverall domestic oil recovery efficiency remains low. This reflectsproduction and proving of 208 billion barrels out of a resource in-placeof 582 billion barrels, in already discovered fields . . . . Includingall these oil resources, truly massive volumes of domestic oil—atrillion barrels—remain ‘stranded,’ after application of currently usedprimary/secondary oil recovery . . . :

“Approximately 374 billion barrels of “stranded” oil remains in alreadydiscovered domestic oil fields, even after application of traditionalTEOR and CO₂-EOR technology.” (DOE Report, page 1, emphasis added.)

The DOE Report goes on to say, inter alia:

“The causes of less-than-optimum, past-performance and only modest oilrecovery by CO₂-EOR include the following: The great majority ofpast-CO₂ floods used insufficient volumes of CO₂ for optimum oilrecovery, due in part to high CO₂ costs relative to oil prices and theinability to control CO₂ flow through the reservoir” (DOE Report, page8).

The DOE Report goes on to state that these “game changer” advances inCO₂-EOR have not yet been developed: “However, the reader should notethat significant new investments are required in research and technologydevelopment for CO₂-EOR to provide the increased domestic oil resourcesand to realize the higher oil recovery efficiencies set forth in thisreport” (DOE Report, pages 5 and 42).

Thus, according to the DOE, if CO₂ can be made more widely available,there would be a very large and highly profitable market for itsapplication.

In addition, William A. Jones, who has over 32 years of experience inthe oil and gas industry, including serving for five years on the Boardof Directors for IPAMS (Independent Petroleum Association of MountainStates), has stated that based on his extensive knowledge and experiencein the oil industry, that there has been a long-felt and unsolved needfor on-site CO₂ production. As stated in the cited DOE Report, thelong-felt need was a recognized problem that has existed in the art fora long period of time without solution. The need has been a persistentone that was recognized by those of ordinary skill in the art, but nosolution was known. Long-felt need was identified and articulated atleast since the early CO₂ floods in 1970s, and there were many effortsto solve the problem. Examples of previous efforts to solve the problemincluded transporting CO₂ by trucks, piping CO₂ from ethanol plants,piping CO₂ from electric power plants, building interstate networks ofpipelines, portable nitrogen generation (N₂ is similar, but not aseffective as CO₂), and many others. All of these attempts were found tobe uneconomical and unsuccessful for most oil fields. The failure tosolve the long-felt need was not due to factors such as lack of interestor lack of appreciation of an invention's potential or marketability.The long-felt need has not been satisfied by any other before thisinvention, which does in fact satisfy the long-felt need.

Preferred System Block Diagram

FIG. 1A shows a block diagram of a preferred embodiment of a reformerpower plant system 100. Water from water tank 112 is compressed in apump 113 into boiler 114, where it is boiled and brought toapproximately 180° C., the boiling point of water at 10 bar. Oxygen 115is added to the steam to create a mixture of steam and oxygen 161. Thesteam-oxygen mixture 161 then passes through heat exchanger 153, whereheat from exiting hot gas pre-heats the steam-oxygen mixture 161 andcools the exiting gas, increasing the overall efficiency of the system100. Carbonaceous fuel 117 and hot steam-oxygen mixture 161 enter steamreformer 122, which operates at approximately 800° C. and 10 bar. Ash iscollected in ash tray 124, from the bottom of the steam reformer 122.The heat to drive steam reformer 122 may be provided by furnace 118,which is fueled by hydrogen gas. Exiting high-pressure gas passesthrough heat exchanger 153, pre-heating the steam-oxygen mixture 161from boiler 114. The exiting high pressure gas 127, which is primarily amixture of CO₂, CO, and H₂, then passes through a water-gas shiftreactor 125, which converts any residual CO into additional CO₂ and H₂(128). The CO₂ and H₂ (127) passes around boiler 114 and water tank 112,further releasing heat to these elements via heat exchanger 154.Finally, exiting driver gas 128 is passed through condenser 126, beforebeing fed to methanol CO₂ separator 128, the operation of which isdescribed in greater detail below. At this point, the high pressure gasis composed primarily of carbon dioxide and hydrogen gas, but may alsoinclude minor constituents of methane gas and carbon monoxide gas, aswell as possibly other gases. The methanol CO₂ separator 128 produces aCO₂ gas stream comprised essentially of CO₂, and a fuel stream 129comprised primarily of hydrogen, but also methane, carbon monoxide, andpossibly other gases. The CO₂ gas stream may be used for EOR 133, or forother purposes. The fuel gas stream 129 is fed into gas turbine 130, aswell as furnace 118. Gas turbine 130 produces electricity via generator131, which may be used locally or fed to the grid 132. Furnace 118 burnsa portion of the fuel gas in order to generate the heat necessary todrive the reforming reaction taking place in the steam reformer 122.

Optionally, additional heat exchangers, such as heat exchangers 151 and152 may be used to exchange heat between the hot exhaust gas exiting thegas turbine and the boiler 114 and water tank 112 to pre-heat and thenboil water.

Alternatively, a methanation reactor (not shown in FIG. 1) may bedisposed downstream of the steam reformer for converting the residualcarbon monoxide into methane. As noted previously, the high-pressure gasmay also include residual methane, which is advantageous, since it makesit easier to combust the hydrogen gas in the gas turbine.

The boiler 114 may operate at a temperature of approximately 150° C. to250° C.

The steam reformer 122 may operate at a temperature of approximately600° C. to 1000° C., and a pressure of approximately 5 bar to 100 bar.The steam reformer may be a fixed bed reformer, a fluidized bedreformer, or an entrained-flow reformer, or another steam reformerdesign known in the art.

The methanol CO₂ separator 128 may operate in a temperature-swing cyclebetween approximately −60° C. and +40° C., a pressure-swing cyclebetween approximately 1 bar and 100 bar, or a combinedtemperature-pressure-swing cycle.

The apparatus may also include a control system adapted to control anoperation of the apparatus based on a market price of carbonaceousmaterial, a market price of electricity, and a market price of crudepetroleum (as described in greater detail below).

The apparatus may also include a control system adapted to control anoperation of the apparatus based on a temperature, a pressure, and a gascomposition of the driver gas in real-time by controlling an inputoxygen-to-steam ratio. Such a control system may be implemented usingnegative feedback control on the injection of oxygen-to-steam ratio intothe steam reformer.

The carbon dioxide-rich driver gas is preferably at least 70% CO₂ byweight, but more preferable at least 90% CO₂ by weight, and even morepreferably at least 97% CO₂ by weight, and even more preferably greaterthan 99% CO₂ by weight.

Heat exchangers, while optional and not a required component of thepresent invention, can be used to greatly increase the thermalefficiency of the power plant shown in FIG. 1A. Accordingly, FIG. 1Bshows an illustrative temperature profile showing placement of heatexchangers wherever there is a temperature difference between hot drivergas exiting the steam reformer and water/steam entering the steamreformer. As shown in FIG. 1B, water at ambient temperature ofapproximately 10° C. enters the system, where it is preheated by aheat-exchanger to slightly less than 180° C. by residual heat in the hotdriver gas exiting the system. After the water is preheated, it isbrought to boiling by the boiler at a temperature of approximately 180°C., since at a pressure of 10 bar, water boils at approximately 180° C.After the water—now steam—exits the boiler, it is further superheatedinto superheated (“dry”) steam via another heat exchanger by the hotdriver gas exiting the water-gas-shift reactor and brought toapproximately 400° C. The steam, now at approximately 400° C., passesthrough a water-gas-shift reactor, where it reacts with any residualcarbon monoxide (CO) exiting the steam reformer. After passing throughthe water-gas-shift reactor, the steam is further superheated toapproximately 800° C. in another heat exchanger before it enters thesteam reformer by exchanging heat with the hot driver gas exiting thesteam reformer. Inside the steam reformer, temperatures can be as highas 1200° C., depending on the ratio of steam:oxygen injected into thesteam reformer. As the water/steam is pre-heated throughout thisprocess, as shown in FIG. 1B, hot driver gas is cooled as it exchangesheat with the water/steam. After the driver gas is finished exchangingheat with the incoming water, it may be further thermally grounded viaany appropriate thermal ground source, such as a river. Thethermally-grounded driver gas may further pass through a condenser, andfinally enter the methanol separator, which produces a liquid stream ofCO₂ at a temperature of approximately −40° C. There may be further heatexchangers located inside the separator. In short, the driver gas iscooled by using the useful heat to pre-heat water. The example givenhere and shown in FIG. 1B is illustrative only of the principles of thepresent invention's heat exchanger design, and is not intended to limitthe scope of the present invention.

FIG. 2 illustrates an example of operations 200 that may be performed inorder to generate electricity and CO₂ for EOR from carbonaceousmaterial. The process begins at operation 201. At operation 202, a pumppressurizes water. At operation 203, steam is generated from thepressurized water, for example, using a boiler. At operation 204, thecarbonaceous material is reformed using steam and oxygen into highpressure gas. At operation 205, a separator separates the high pressuregas into CO₂ and H₂ rich gases. At operation 206, the carbon dioxide isused for enhanced oil recovery and/or used for other beneficialpurposes. The rest of the driver gas, which may include hydrogen gas, aswell as minor amounts of methane, carbon monoxide, as well as othergases, are combusted in order to generate electricity and heat, as shownin operation 207. In one example, operation 207 may include combustionof hydrogen and small amounts of methane, in order to provide energy,for instance, within a gas turbine, an internal combustion engine, or afuel cell. At operation 208, heat passes through a heat exchanger tohelp drive the reformation reaction. The energy generated from thecombustion may be used to heat the feedstock to a temperature where thecarbonaceous material reacts with water to form a hydrogen and carbondioxide-rich high pressure gas, as described in operation 204. Note thatthe energy used to drive the reforming reaction, and to boil water andproduce superheated steam, can also be provided from burning a fuelother than hydrogen, or biomass, or from a non-combustible source, forexample, solar energy, nuclear energy, wind energy, grid electricity, orhydroelectric power (not shown in FIG. 2). At operation 209, heat fromthe exiting high pressure gas exchanges heat with the boiler. Some ofthe heat from the combustion reaction is used to help generate steam inthe boiler, as shown in operation 209. Finally, the electricity may beused locally or transmitted to the local grid, as shown in operation210. The process 200 ends in step 211. Optionally, pure oxygen may bepre-mixed with the steam to increase reforming yield.

Embodiments of the present invention provide various reformer apparatussubsystems for generating high-pressure gas. In some embodiments, theapparatus utilizes a biomass reforming reaction to generate the highpressure gas and a hydrogen combustion reaction to provide the energyrequired to reform biomass and generate the high-pressure gas. Inaddition, the apparatus typically includes heat exchange elements tofacilitate heat transfer from the high temperature gas to incomingreformer and/or combustion fuel. The transfer of heat facilitates thereforming reaction and lowers the energy required to complete the drivergas formation. An illustrative embodiment is described in relation toFIG. 3 for separate reformer and combustion reactions, followed by anembodiment described in relation to FIG. 4 for autothermal reforming andproduction of high-pressure gas by a single reaction chamber.

Indirect Reformer Subsystem

FIG. 3 illustrates an example of a steam reforming apparatus 300 forgenerating high pressure gas (shown as arrow 302), in accordance withone embodiment of the present invention.

In FIG. 3, an embodiment of the reforming subsystem may include a firststorage container (not shown) for storing a combustible material, suchas coal, biomass, an alcohol, olefin, or other like material. A secondstorage container (not shown) may also be provided for storing thecarbonaceous fuel for the reforming reaction. The water may be mixedwith the carbonaceous fuel in this container to form slurry.Alternatively, a third container (not shown) may be used to store waterto be reacted with the feedstock in the reformer chamber.

In one example, a first chamber 304 has an inlet port 316 and an outletport 310 and is adapted to provide for the combustion of the combustiblematerial. In one example, the first chamber 304 includes an igniter suchas a spark plug 312 or other conventional igniter, and a nozzle 314coupled with the inlet port 316 of the first chamber 304. The inlet port316 of the first chamber 304 may be coupled with the first storagecontainer (not shown) so that the contents of the first storagecontainer may be introduced into and combusted within the first chamber304. The first chamber 304 also includes a port 308 for introducingcombustion air, or pure oxygen, into the first chamber 304. The firstchamber 304 is also adapted to receive a portion of the second chamber306, described below, so that the energy/heat from the combustion of thecombustible material from the first storage container (not shown) withinthe first chamber 304 is transferred into a portion of the secondchamber 306. The outlet port 310 of the first chamber 304, in oneexample, is near the inlet port 320 of the second chamber 306, and aheat exchanger 318 is used to allow the combustion exhaust gas to heatthe carbonaceous fuel and water entering the second chamber 306.Alternatively, the outlet 310 of the first chamber 306 can feed to aheat exchanger located inside the second chamber 306, which therebyallows the combustion exhaust gases produced in the first chamber 304 toprovide the heat to drive the reforming reactions in the second chamber306.

The second chamber 306 has an inlet port (shown as arrow 320) and anoutlet port 302. In one example, the inlet port 320 is coupled with thesecond and third storage containers (not shown) and receives thecontents of the second and third storage containers (not shown).

In one example, the second chamber 306 is positioned within the firstchamber 304, such that the combustion heat/energy from the first chamber304 heats the carbonaceous fuel and water sources contained within thesecond chamber 306 to a point where the carbonaceous fuel reforms into ahigh-pressure gas which exists out of the outlet port 302 of the secondchamber 306. The first and second chambers may be fluidly isolated.

In one embodiment, shown in FIG. 3, the reformer feed entering the inletport 320 may be a single fluid, for example carbonaceousfuel-water-oxygen slurry. In other embodiments, not shown in FIG. 3, thecarbonaceous fuel and water-oxygen mixture may be fed into the reformerchamber through separate inlets.

In one example, a first heat exchanger 318 is coupled with the outletport 310 of the first chamber 304 (the combustion chamber) and isthermodynamically coupled with a portion of the inlet port of the secondchamber 306. In this manner, the hot combustion exhaust gases from thefirst chamber are used to preheat the carbonaceous fuel and watersources as they are being introduced into the second chamber 306 forreformation into a high-pressure gas.

A second heat exchanger 326 may also be utilized, wherein the secondheat exchanger 326 is thermodynamically coupled with the outlet port 302and the inlet port 320 of the second chamber 306, which provides thedual benefit of preheating the carbonaceous fuel and water sources priorto entry into the second chamber 306, as well as cooling the driver gaswhich is expelled from the outlet port 302 of the second chamber 306.

Notwithstanding the above examples, the present invention does notrequire the use of heat exchangers. The use of heat exchangers isoptional. Heat exchangers may be used to increase the efficiency of thereformer subsystem. However, there may be situations in which heatexchangers would not be used, such as when hot gas is desired and/orwhen the carbonaceous fuel and water sources are pre-heated by othermeans.

Autothermal Reformer Subsystem

FIG. 4 illustrates another example of a steam reforming subsystem 400for generating high-pressure gas in accordance with another embodimentof the present invention. The embodiment illustrated in FIG. 4 providesan “autothermal reformer” for the production of high-pressure gas. Anautothermal reformer 400 of the present invention directly reacts acarbonaceous fuel source with water as well as oxygen, air, or otheroxidizers in a single chamber 402. Embodiments of the reformer providean environment for reforming carbonaceous fuel from a feed at propertemperature and pressure resulting in the release of high-pressure gas.

Referring to FIG. 4, an autothermal reformer apparatus 400 is shownhaving a reaction chamber 402, a carbonaceous fuel-water slurry deliverypipe (fuel pipe) 404 for delivery of a mixture of carbonaceous fuel andwater, a driver gas outlet port (outlet port) 406 for release ofproduced high-pressure gas 418, and an oxygen or other oxidizing gasinlet pipe (gas pipe) 408 for delivery of an oxidizing gas used in thecombustion of the carbonaceous fuel in the reaction chamber. Theoxidizer may also be pre-mixed with the fuel-water slurry or pre-mixedwith steam.

Still referring to FIG. 4, the reaction chamber 402 is of sufficientsize and shape for autothermal reforming of carbonaceous fuel. Differentchamber geometries can be used. In the embodiment shown in FIG. 4, thefuel pipe 404 is coupled to the outlet port 406 to form acounter-current heat exchanger 412 so that the energy/heat from theexiting driver gas is transferred to the carbonaceous fuel-water slurryentering the reaction chamber 402 via the fuel pipe 404. In addition,the fuel pipe 404 typically enters at a first or top end 414 of thereaction chamber 402 and releases the fuel toward the second or bottomend 416 of the reaction chamber 402. This configuration enhances heatreleased from the heated carbonaceous fuel-water slurry into thecontents of the reaction chamber 402. Release of fuel into the reactionchamber 402 can be via an outlet 417 or other like device. The gas pipe408 is typically coupled to or adjacent to the fuel pipe 404 andreleases the oxygen or other oxidizing gas adjacent to the release ofthe carbonaceous fuel-water slurry 415. When in use, the reactionchamber of the autothermal reformer apparatus is typically preheated toa temperature sufficient to start the reforming reaction, i.e.,approximately 500° C., and preferably above approximately 800° C.Preheating may be accomplished by a reaction chamber integrated heatingelement, a heating coil, an external combustor heating system, aninternal combustion system, or other like device (not shown).

The carbonaceous fuel and water sources are fed into the reactionchamber 402 via the fuel pipe 404. At approximately the same time thatthe carbonaceous fuel-water slurry is being delivered to the reactionchamber 402, the oxygen or other oxidizing agent is being delivered tothe reaction chamber via the inlet pipe 408. Various reformer chemicalreactions are described below. Once the reforming reaction has beenestablished within the reaction chamber 402, the reaction-chamberheating element may be shut off to conserve energy. Note also that theamount of water combined into the carbonaceous fuel slurry can beadjusted to control the reforming temperatures.

While the example shown in FIG. 4 depicts carbonaceous fuel and waterbeing fed into the reactor together in the form of carbonaceousfuel-water slurry, this is illustrative of only one embodiment. In otherembodiments, shown in FIG. 5 and FIG. 6, carbonaceous fuel and water maybe fed into the reaction chamber through separate inlets. Also, in otherembodiments, not shown, additional combustible material, such as naturalgas, oil, charcoal, or any other fuel may be fed into the reactionchamber (in addition to the carbonaceous fuel) in order to facilitateinitial system start-up or reactor temperature maintenance. The use ofsuch additional fuel(s) may also be used to provide additional reformingreaction material or to change the hydrogen/carbon dioxide output ratioof the system. All such embodiments are envisioned to be within thescope of the present invention.

Variety of Carbonaceous Fuels

Embodiments of the present invention provide processes for producinghigh-pressure gas from the reforming of carbonaceous fuel or derivativesof carbonaceous fuel (as described above). Examples of fuel sources thatmay be used in the reforming reaction include, but are not limited to,biomass, coal, urban and municipal trash, forestry residue, methanol,ethanol, propane, propylene, toluene, octane, diesel, gasoline, crudeoil, and natural gas, and in general any carbonaceous (orcarbon-containing) compound, such as human or animal waste, plasticwaste (for example, used tires). A similar subsystem apparatus may beused to reform these fuels.

The present invention provides reforming processes of carbonaceous fuelor carbonaceous fuel-derivatives to generate, for example, H₂, CO₂, andother gases. The fuel reforming reactions of the present invention areendothermic, requiring an input of energy to drive the reaction towardfuel reformation.

In one embodiment, the energy required to drive the carbonaceous fuelreforming reaction is provided through the combustion of any combustiblematerial, for example, hydrogen, an alcohol, a refined petroleumproduct, crude petroleum, natural gas, or coal that provides thenecessary heat to drive the endothermic steam reforming reaction.

In other embodiments, the energy required to drive the reformingreaction is provided via any non-combustible source sufficient togenerate enough heat to drive the reforming reaction to substantialcompletion. Examples of non-combustible sources include solar, nuclear,wind, grid electricity, or hydroelectric power.

In a preferred embodiment, shown in FIG. 1A, a portion of the hydrogengas generated by the reformer is used in the combustion chamber(furnace) to provide heat for the steam reformer.

Reactions 1-4 above provided illustrative processes for reformingcarbonaceous fuel to produce high-pressure gas. Various fuels, such asbiomass, coal, alcohols, petroleum, natural gas, etc. may be used as thefuel source for the reforming reaction. Reactions 5-11 illustrateseveral other reforming reactions using alternative fuel sources thatare in accordance with the present invention. The following reactionsillustrate a separation of the reforming and combustion reactions;however, as shown in FIG. 4, an autothermal reforming reaction may beaccomplished by directly reacting the carbonaceous fuel with oxygen in asingle reaction chamber.

Coal: C+2H₂O→CO₂+2H₂  (5)

Methane: CH₄+2H₂O→CO₂+4H₂  (6)

Ethanol: C₂H₅OH+3H₂O→2CO₂+6H₂  (7)

Propane: C₃H₈+6H₂O→3CO₂+10H₂  (8)

Propylene: C₃H₆+6H₂O→3CO₂+9H₂  (9)

Toluene: C₇H₈+14H₂O→7CO₂+18H₂  (10)

Octane: C₈H₁₈+16H₂O→8CO₂+25H₂  (11)

In alternative embodiments, olefins, paraffins, aromatics (as found incrude petroleum), or crude petroleum itself may be used as the reformingreaction fuel source.

Fuel Reformer Subsystem Design Options

The present invention provides for at least three possible carbonaceousfuel-steam reformers, but is not limited to the three carbonaceous fuelreformers described here. These include the fixed-bed reformer (FIG. 5),the fluidized-bed reformer (FIG. 6), and the entrained-flow reformer(not illustrated). The carbonaceous fuel reformers increase incomplexity in the order listed. The solids-residue handling requirementsalso increase in complexity in the same order. However, reaction ratesalso increase in the same order, leading to reduced equipment sizes fora given throughput. Each carbonaceous fuel-steam reformer may beimplemented as an indirect reformer configuration (as shown in FIG. 3),or as an autothermal reformer configuration (as shown in FIG. 4).

Table 1 shows important features that distinguish the three possiblecarbonaceous fuel-steam reformers. Values are shown to illustraterelative differences in the reformer parameters.

TABLE 1 Operating parameters of various carbonaceous fuel-steamreformers Fixed-Bed Fluidized-Bed Entrained-Flow Operating ReformerReformer Reformer Parameter (FIG. 5) (FIG. 6) (not illustrated) FeedParticle Size approx. <1″ approx. <¼″ approx. <0.1″ Temperatureapprox. >700° C. approx. >800° C. approx. >1,200° C. Solids Retentiongreatest intermediate shortest Time Gas Retention longest shortershortest Time

All three carbonaceous fuel-steam reformers operate at sufficienttemperature to eliminate catalyst requirements for steam reforming. Thefixed-bed and fluidized-bed reformers are able to accept carbonaceousfuel of the delivered particle size. The entrained-flow reformer wouldrequire additional grinding or pulverizing of the carbonaceous fuelafter delivery.

In one embodiment of the present invention 500, depicted in FIG. 5, afixed-bed fuel-steam reformer 501 is used to generate high-pressuredriver gas. In the reaction chamber of the fixed-bed reformer, nearlyall the feed and residue particles remain in reaction chamber 501 duringreforming. Delivered carbonaceous fuel 502 with a feed particle size ofapproximately less than 1-inch is introduced into hopper 503. Thecarbonaceous fuel 502 is then fed into fixed-bed reformer 501 throughfeeder 504. Steam (shown as arrow 506) is also fed into the fixed-bedreformer 501. In one embodiment, heat recovered from the reformer gas isdirected into heat recovery unit 507. The heat can be sent to steamgenerator 510 to convert water (shown as arrow 508) into steam (shown asarrow 506). Furnace 505, which may be fueled by hydrogen and/orcarbonaceous material, provides the necessary heat to drive the reformer501. In one embodiment, oxygen 511 may be introduced into the fixed-bedreformer 501, either through a separate inlet, or pre-mixed with thesteam 506 as shown in FIG. 5, in order to increase the reforming volumesusing an autothermal reaction.

The fixed-bed reformer can be fed and discharged in batch mode,semi-batch mode (incremental feeding and discharging of ash), orcontinuous mode. In the fixed-bed reformer, the coarse ash 514 remainingafter steam reforming is largely handled in the form of coarserparticles that can be removed from the bottom of the reactor. Coarse ash514 can be considered a byproduct in the system with a clast sizegreater than 0.063 millimeters. Smaller remaining amounts of ash areentrained in the low velocity exhaust gas exiting the reformer. Thisfine ash 510 of clast size less than 0.063 millimeters is removedthrough bag filter 512. The filtered, high-pressure driver gas is thensent to gas separator 514, which separates the high pressure driver gasinto a fraction rich in CO₂ gas, and a fraction rich in H₂ (fuel gas).The CO₂-rich gas may then be easily used for EOR 520, since it ishigh-pressure, high-purity CO₂. The H₂-rich fuel gas, which may alsocontain minor amounts of methane and carbon monoxide, may then be fed togas turbine 516, where it is combusted with air to provide electricityto the electric grid 518, or used on-site at for oil field operations.Since the H₂-rich fuel gas combusts with little or no associated CO₂emissions into the atmosphere, the electricity generated by gas turbine516 may be considered to be “carbon-free” electricity.

In an alternative embodiment 600, depicted in FIG. 6, a fluidized-bedreformer 601 is used to generate high pressure gas. In the fluidized-bedreformer 601, most particles remain in the reaction chamber, but finerparticles are entrained with the exhaust gas. That is, compared to thefixed-bed reformer 501 of FIG. 5, greater amounts of fine particles areentrained in the higher velocity exhaust gas (relative to the exhaustgas generated in the fixed-bed reformer) and must be removed prior tocompression of the driver gas. The coarsest of the entrained particlesare removed from the gas stream and can be recycled to the reformer ordischarged as residue. The remaining finest particles are removed byfiltration.

FIG. 6 illustrates an example of an embodiment of a system utilizing thefluidized-bed reformer 601. Delivered carbonaceous fuel 602 with a feedparticle size of approximately less than ¼-inch is introduced intohopper 603. The carbonaceous fuel is fed into fluidized-bed reformer 601upon opening of the rotary valve 604. In the fluidized-bed reformer 601,steam (shown as arrow 606) is also fed into the reaction chamber.Furnace 605, which may be fueled by hydrogen and/or carbonaceous fuel,provides the necessary heat to drive the reformer 601. In oneembodiment, oxygen 613 may be introduced into the fluidized-bed reformer601, either through a separate inlet, or pre-mixed with the steam 606 asshown in FIG. 6, in order to increase the reforming volumes using anautothermal reaction.

It is noted that in the fluidized-bed reformer 601, continuous feedingwith semi-continuous discharge of coarser ash 607 is preferable.Intermediate ash 608 in exhaust gas exiting the fluidized-bed reformer601 is removed by cyclone separator 609 (to remove intermediate-sizedparticles) and bag filter 610 (to remove the finest particles of ash611). The intermediate-sized particles separated by cyclone 609 can berecycled to the fluidized-bed reformer 601 or removed as residue,depending on the extent of their conversion during reforming. In oneembodiment of the fluidized-bed reformer 601, exhaust gas existingcyclone 609 enters heat recovery unit 614. The heat can be sent to steamgenerator 615 to convert water (shown as arrow 616) into steam (shown asarrow 606). The CO₂ separator 618 separates the high pressure driver gasinto a CO₂-rich gas and a H₂-rich fuel gas. The CO₂-rich gas may bedirected for EOR 624. The H₂-rich fuel gas may be provided to a gasturbine 620. The gas turbine 620 combusts the H₂-rich fuel gas with airto generate electricity, using for example a generator (not shown); andthe electricity may then be fed to the electrical grid 622. Since theH₂-rich fuel gas combusts with little or no associated CO₂ emissionsinto the atmosphere, the electricity generated by gas turbine 620 may beconsidered to be “carbon-free” electricity.

In another embodiment of the present invention (not illustrated), anentrained-flow reformer is used rather than a fixed-bed or fluidized-bedreformer. In an entrained-flow reformer, virtually all particles areremoved with the exhaust gas steam exiting the reformer. The feedparticle size using the entrained-flow reformer is generally less thanapproximately 0.1 inch. Compared to the fixed-bed and fluidized-bedreformers, the entrained-flow reformer would require additional grindingor pulverizing of the carbonaceous fuel after delivery. Furthermore,with the entrained-flow reformer, the entire feed stream is entrainedand removed from the reaction chamber at high velocity. Cyclone andfiltration hardware similar to those of the fluidized-bed reformer areused, but removal capacities must be greater.

In other embodiments of the present invention, (not illustrated in FIG.5 or FIG. 6), carbonaceous fuel-water slurry may be used to provide bothcarbonaceous fuel and water into the reformer in liquid form via asingle feed system, as shown in FIG. 3 and FIG. 4.

The reformers may operate at sufficient temperature to eliminatecatalyst requirements for steam reforming Generally, the fixed-bedreformer may operate at temperatures above approximately 700° C., whilethe fluidized-bed reformer may operate at temperatures aboveapproximately 800° C. The entrained-flow reformer may operate attemperatures in excess of approximately 1,200° C. These temperatureranges are illustrative only, and are not intended to limit the scope ofthe present invention. All carbonaceous fuel-steam reformers may operateover temperature ranges other than those temperature ranges disclosedhere.

The fixed-bed reformer 501 of FIG. 5 and fluidized bed reformer 601 ofFIG. 6 may be designed as illustrated in FIG. 3 or FIG. 4. That is, thesteam reforming of carbonaceous fuel can be carried out using anindirect reformer, as in FIG. 3, or a direct (“autothermal”) reformer,as depicted in FIG. 4. Indirect reforming requires heat exchange betweenthe heat source (H₂ fuel combustion, for example) and the reformer. Highpressure gas produced from indirect steam reforming results in greaterhydrogen:carbon dioxide ratio than gas produced from direct(“autothermal”) reforming. It will be appreciated that the combustiblematerial may be hydrogen (H₂), or alternatively may be an alcohol,olefin, natural gas, oil, coal, biomass or other combustible source.

Autothermal reforming eliminates the heat exchange requirement sincepartial combustion is performed in the reforming reaction chamber togenerate heat. Using oxygen for the oxidizer, the autothermal reformerproduct gas is still a mixture of carbon dioxide and hydrogen, but thehydrogen:carbon dioxide ratio is lower than that for indirect reforming.Using air as the oxidizer, the autothermal reformer product gas isdiluted with nitrogen, which may be undesirable in cases where highpurity CO₂ is required.

Illustrative carbonaceous fuel reformers have been described and shownhere. However, the present invention is not limited to thesecarbonaceous fuel reformer configurations, and other carbonaceous fuelreformers are within the scope of the present invention.

Sulfur Removal

Most carbonaceous fuel has some sulfur. Because steam reforming may beperformed without catalyst, reforming catalyst poisoning by sulfurcompounds is not an issue. In cases where a low-sulfur carbonaceous fuelis used, sulfur clean up of the exhaust gas may not be required at all.In the event of potential issues with corrosion caused bysulfur-containing gases in combination with any residual moisture,several sulfur treatment and removal methods are possible.

Dry sorbents may be used to capture sulfur in the exhaust gas. Calciumoxide, magnesium oxide, and sodium carbonate are example dry sorbentsthat are capable of trapping sulfur gases in solid form (as sulfates orsulfites, depending on the relative oxidation conditions). When theoperating temperature and pressure permit effective sulfur capture,sorbent can be added in a coarse form with the feedstock to fixed- orfluidized-bed reformer configurations. The resulting sulfur-containingproduct can then be removed from the reaction chamber with the ashremaining after reforming. Alternatively, a finer sorbent can beinjected into the gas downstream of the reactor. Sulfur containingsolids can then be collected in the cyclone or bag filter. For theentrained-flow reformer configuration, a sorbent will likely performbetter by injection into partially cooled gas downstream of thereformer.

In large-capacity reformer configurations, a dry sorbent may be injectedin a separate unit downstream of the final ash particulate filter. Thesulfur product can then be collected separately in another filter andcan potentially be sold as a product for additional revenue.

In other embodiments, sulfur may also be removed by using a wet scrubbersub-system. Wet scrubbers can be configured in venturi, packed-column,or tray-type systems in which the cooled gases are contacted with ascrubbing solution or slurry. The resulting scrubber solution or slurrymust then be disposed.

The use of the methanol CO₂ separation system described below has theadditional benefit of removing sulfur impurities from the CO₂ gasstream.

Preferred CO₂ Separation Subsystem

According to the present invention, highly economic CO₂ and H₂generation system is disclosed. The CO₂ and H₂ are generated from anycarbonaceous fuel source including biomass, coal, or natural, highlyeconomical fuel sources and ones that are available almost anywhere. TheCO₂ generated in the present invention may be injected into an oil wellfor enhanced oil recovery or used for other beneficial purposes. Thepresent invention also generates large supplies of hydrogen, which maybe split off from the CO₂ product to be used for many purposes,including electrical power generation or petrochemical hydrogenation.

In an alternative embodiment, the hydrogen gas may be sold to thepetrochemical or other industry. In the future, it may also be sold asfuel for hydrogen-electric vehicles. Alternatively, the hydrogen may beburned to generate electricity, using a gas turbine, an internalcombustion engine, a fuel cell, or the like. The electricity may be soldto utility companies by feeding the electricity into the electric gridor used locally for oil field operations.

Carbon dioxide is approximately two orders of magnitude more soluble inmethanol than any of methane, hydrogen, nitrogen, oxygen, or carbonmonoxide (which all have solubilities of the same order). The methanolalso acts as a trap, removing sulfur impurities from the gas stream. Inexperiments done to date, the inventors have shown that at 10 barpressure and 10° C., methanol will take into solution about 40 grams perliter of CO₂ from a 40% CO₂/60% N₂ gas mixture, with less than 2grams/liter of N₂ entrained.

The inventors have used this data to create a system where liquidmethanol is pumped in a cycle from 1 bar to 10 bar, with the gas mixbeing bubbled through a column on the 10 bar side, and captured gasallowed to outgas from solution on the 1 bar side. Results to date showthat product gas purities of 95% CO₂ can be obtained, with 80% of theinput CO₂ in the feed gas stream being captured into the product stream.The fraction captured could be increased further to better than 95% byheating the methanol in the low pressure tank to 40° C., which could bereadily done using low-quality waste heat from either the steam reformeror power generation systems. Warming the methanol in this manner wouldincrease the methanol vapor pressure in the exhaust to about 0.3 bar,but nearly all of the entrained methanol vapor could be condensed andremoved by running a low-cost −18° C. refrigerator downstream of theexhaust vessel. This unit would also reduce the CO₂ temperature to −18°C., which is advantageous, as it allows CO₂ gas to be liquefied bysubsequent compression to only 20 bar.

However, in order to eliminate the large majority of this compressionenergy work, reduce methanol recirculation pump work by an order ofmagnitude, and to obtain both CO₂ product recoveries and purities ofbetter than 97%, a preferred system configuration may be used that usesmethanol cooled to −60° C. in the absorption column. Such a column canacquire CO₂ in the liquid phase, forming mixtures that are more than 30%CO₂ by weight, with only insignificant qualities of non-CO₂ gasesbrought into solution. Upon being warmed in the desorption column to 40°C., nearly all the CO₂ is stripped, and removed from the system at 10bar, making subsequent liquefaction straightforward. In the preferredembodiment, the heating of the methanol occurs at the bottom of thedownflowing desorption column, with cold CO₂-saturated methanol on top,so that very little methanol vapor escapes with the product CO₂.

In the process of liquefaction, nearly pure CO₂ is obtained, as neitherhydrogen, methane, oxygen, nitrogen, nor carbon monoxide will beliquefied at −60° C. Once the CO₂ is liquefied, it can be brought towhatever high pressure is required for underground injection at littleenergy cost.

The non-CO₂ product gases, which will be a mixture of hydrogen, methane,and small amounts of carbon monoxide, are sent directly to a gas turbinewhere it is burned to produce electricity.

Alternative CO₂ Separation Subsystems

Various alternative techniques may be used to separate hydrogen gas fromcarbon dioxide gas, in additional to the methanol-CO₂ separationtechnique described above. In one embodiment, hydrogen-carbon dioxideseparation may be performed using membranes. The membranes separatemolecules based on their relative permeability through various materialsthat may include polymers, metals, and metal oxides. The membranes arefed at elevated pressure. Permeate is collected at lower pressure whilethe retentate is collected at a pressure close to the feed pressure.

A membrane separation technique that may operate in conjunction withreactions at elevated temperature is the palladium membrane. Thismembrane, which may be fabricated using palladium alone or incombination with modifiers, allows only hydrogen to permeate. This typeof membrane, when operated in a catalytic reactor, such as in a steamreformer, enhances yield by removing a reaction product from thereaction zone. Some variants are capable of operation at up to 900° C.

Another membrane separation method that may be used is ahigh-temperature polymer membrane. This type of membrane is directedtoward CO₂ separation and recovery. A polymeric-metal membrane of thistype can operate at up to 370° C. (versus typical polymer membranemaximum temperatures of about 150° C.), thus potentially improvingprocess energy efficiency by eliminating a pre-cooling step.

In yet another embodiment, carbon dioxide may be separated from hydrogenby scrubbing in an amine solution. This technique may be used to removecarbon dioxide (and hydrogen sulfide) from the high-pressure gas.

Finally, in yet another embodiment, regenerable sorbents may be used toseparate hydrogen gas from carbon dioxide gas. In one example of alow-cost regenerable sorption method, a sodium carbonate sorbent isused. The sodium carbonate sorbent operates cyclically, by absorbing atabout 60° C. and regenerating at about 120° C.

As described in the preferred CO₂ separator section, processes thatgenerate high CO₂ concentrations are more amenable to affordable gasseparation. Elimination of diluents such as nitrogen from air greatlyimproves CO₂ capture efficiency. In addition, processes that produce CO₂at elevated pressure are at an advantage for the pressure-basedseparation techniques.

Various gas separator modules may be used, and the present invention isnot limited to the particular gas separators shown or described herein,so long as the gas separators perform at least the function ofseparating CO₂ from the rest of the driver gas.

System Design Using a Modular Configuration

The present invention may also be configured as a modular system, whichmay include all or part of the following set of components: a steamreformer, a gas separator, heat exchangers, a power generator, and acontrol system. These components may be mixed and matched depending onthe particular application, and the requirements of a particular user.These components are described in detail throughout this disclosure.

A carbonaceous fuel reformer module is provided that is capable ofreacting carbonaceous fuel with water to produce a mixture of CO₂ andhydrogen gas, sized to an output rate appropriate for the application.Depending upon the availability and cost of local carbonaceous fueltypes, the reformer may be designed to operate with various candidatecarbonaceous fuel feed-stocks. The carbonaceous fuel reformer may bedesigned as a fixed-bed reformer, a fluidized-bed reformer, anentrained-flow reformer, or another design altogether. The carbonaceousfuel reformer may be designed in a direct reforming configuration, or anindirect (“autothermal”) reforming configuration. Examples of the designof such carbonaceous fuel reformers are discussed above in relation toFIGS. 3-6.

A set of heat exchangers is provided that are designed to maximize thethermal efficiency of the reformer system. The heat exchangers werediscussed above in relation with the fuel reformers of FIGS. 3 and 4.

A gas separator module is provided that is capable of separating the CO₂from the hydrogen gas. Candidate separator systems include methanoltemperature and/or pressure swing, sorption beds, CO₂ freezers,membranes, and centrifugal separators, as described above.

A power generator module is provided that is capable of utilizing thehydrogen product separated by the gas separator to generate electricity.The power generator may be a gas turbine, an internal combustion engine,a fuel cell system, or any other apparatus or system that can generatepower (electrical or mechanical or other) from hydrogen, methane, and/orcarbon monoxide gas.

A control module is provided that is capable of controlling theoperation of the system both automatically and with user-input. Thecontrol module may use subsurface data to automatically regulate theoperation of the system via feedback control. This allows the system tooperate with minimal human supervision or labor. The subsurface data mayinclude total pressure, partial pressure of carbon dioxide, partialpressure of hydrogen, temperature, and/or viscosity of the oil. Thecontrol module may also include a set of controls for user-control ofthe system.

The control system may be used to control the power plant based on thelocal prices of electricity, carbonaceous feedstock, water, and thevalue of the product produced via the beneficial reuse of CO₂. That is,if the local price of electricity has increased and/or there is a demandfor more power, the control system may divert more of the hydrogen toelectricity generation. The opposite condition may hold if the localprice of electricity dropped or if the market price of the productproduced via the beneficial reuse of CO₂ rose; in this case the controlsystem may divert more of the hydrogen gas and CO₂ gas for beneficialuse. This optimization operation may be performed automatically by acontrol module based on real-time inputs of market prices and otherparameters.

According to another embodiment, the control system may be used tocontrol the power plant based on a temperature, a pressure, and a gascomposition of the driver gas in real-time by controlling an inputoxygen-to-steam ratio. Such a control system may be implemented usingnegative feedback control on the injection of oxygen-to-steam ratio intothe steam reformer.

A gas capture module is provided that is capable of re-capturing aportion of the CO₂ gas and recycling the gas. The gas capture moduleallows the CO₂ that is released with the oil emerging from the ground tobe re-captured and sent via the compressor module underground for reuse.The gas capture module increases the overall efficiency of an oilrecovery operation, because a portion of the generated CO₂ gas isrecycled and reused.

In one embodiment, a gas capture module is created by pumping the oilinto a vessel with a certain amount of ullage space above the oil, anddrawing suction on the ullage with another pump. This operation willlower the vapor pressure of carbon dioxide above the oil, allowing gasesin solution to outgas so that they can be recycled back into the well.Various gas capture modules are within the scope of the presentinvention, and the present invention is not limited to the particulargas capture modules or methods shown or described here, as long as thegas capture modules or methods are capable of capturing at least aportion of the gas emerging with the oil from the oil well.

Power Generation Subsystem

The hydrogen gas separated by the gas separator module may be used togenerate power. The power generator module utilizes a portion of thehydrogen gas separated by the gas separator module to generate power. Inone embodiment, the power generator module is used to generateelectricity. In one embodiment, the electricity is sold to a utilitycompany by feeding the electricity into the electric grid. The powergenerator module may be a combustion turbine, a steam turbine, a fuelcell, or any other apparatus, system, or module that can generate power(electrical or mechanical or other) from hydrogen gas.

According to one embodiment of the power generator module utilizing acombustion turbine, hydrogen is fed with air to generate power through arotating shaft. Designs of hydrogen gas turbine plants are described inU.S. Pat. No. 5,755,089 to Vanselow, U.S. Pat. No. 5,687,559 to Sato,and U.S. Pat. No. 5,590,518 to Janes. Designs of hydrogen internalcombustion engines are described in U.S. Pat. No. 7,089,907 to Shinagawaet al., U.S. Pat. No. 4,508,064 to Watanabe, and U.S. Pat. No. 3,918,263to Swingle.

Another embodiment of the power generator module uses a steam turbine. Avariety of fuels may be used, including a portion of the separatedhydrogen, part of the coal or other feedstock material, or even wastehydrocarbon gases. The fuel is burned in air in a combustion chamber togenerate heat. The heat is transferred to a closed-loop steam/watersystem through a series of heat exchangers designed to recover thecombustion heat. The high-pressure steam drives a turbine for powergeneration. In one embodiment, the combustion turbine and steam turbinemay be integrated to boost efficiency (integrated combined cycle).

As an alternative to combustion, in one embodiment of the presentinvention, a fuel cell module may be used to convert hydrogen directlyto electricity, usually with greater efficiency albeit at a highercapital cost. The fuel cell module, an electrochemical energy conversiondevice, produces electricity from the hydrogen fuel (on the anode side)and oxidant (on the cathode side). The hydrogen and oxidant (which maybe ambient oxygen) react in the presence of an electrolyte. Thereactants (hydrogen and oxygen) flow in and reaction products (water)flow out, while the electrolyte remains in the cell. The fuel cell canoperate virtually continuously as long as the necessary flows ofhydrogen and oxidant are maintained. Designs of fuel cell plants aredescribed in U.S. Pat. No. 6,893,755 to Leboe, U.S. Pat. No. 6,653,005to Muradov, U.S. Pat. No. 6,503,649 to Czajkowski et al., U.S. Pat. No.6,458,478 to Wang et al., U.S. Pat. No. 5,079,103 to Schramm, U.S. Pat.No. 4,659,634 to Struthers, and U.S. Pat. No. 4,622,275 to Noguchi etal.

Various power generator modules are within the scope of the presentinvention, and are not limited to the particular power generators shownor described here, so long as the power generators can generate power,whether electrical, mechanical, or other, from hydrogen-rich gas.

Natural Gas Reformer Module

In one embodiment of the present invention, natural gas—either locallyproduced, stranded, or imported from off-site—may be used as the fuelsource for the reforming reaction. This is highly convenient, and undersome conditions may be highly advantageous from both a logistical and aneconomic perspective. Accordingly, in one embodiment of the presentinvention, a natural gas reformer module is used.

FIG. 7 shows a schematic of a system 700 utilizing a catalytic naturalgas reformer module 707. Natural gas from a natural gas source 701,either from off-site or on-site, is fed via a line into sulfur removalmodule 703, if necessary to remove sulfur. Desulfurized natural gas isfed via another line into methane reformer module 707. Steam from boiler705, and optionally oxygen from oxygen tank 704, is added to methanereformer module 707. The exhaust driver gas exiting the methane reformermodule 707 is passed through a set of heat exchangers (not shown). Thecooled driver gas is passed to separator module 709, in which it isseparated into a portion rich in hydrogen gas 711, and a portion rich inCO₂ gas. The CO₂-rich gas portion is sent to compressor module 711. Thecompressor module 711 compresses the CO₂-rich driver gas to a pressureappropriate for the oil well. Finally, the high pressure CO₂-rich drivergas 713 is injected via an injection line into injection well 715. Theoil is recovered using the same injection well 715 (“Huff-and-Puff”) oranother production well 717. After oil recovery 719, natural gas 723 maybe separated from the oil in a natural gas separator 721, and suppliedto sulfur removal module 703 to provide fuel for the methane reformer.In short, local, stranded, or off-site natural gas may all be used toprovide fuel to drive the methane reformer 707. The hydrogen gas 711 isfed to gas turbine 725, where it generates electricity via generator727, which may be fed to the electric grid 729 or used on-site. As withthe coal reforming modules, heat recovered from the natural gas reformermodule may be used to generate electrical or mechanical power to drivethe compressor module or other system hardware.

If refined, desulfurized natural gas is used, no gas clean up isrequired. That is, the sulfur removal module 703 in FIG. 7 is not neededand may be removed. If raw natural gas is used, sulfur must generally beremoved before the reformer module 707 to prevent catalyst poisoning.Sulfur contained in natural gas can be removed on catalysts or sorbentssuch as zinc oxide, activated carbon (with chromium or copper), nickeloxide, or certain molecular sieves (13×). Some of these sorbents work atambient temperature; others require elevated temperatures. Oncecaptured, the sorbents may be disposed or regenerated. Many of thesorbents release trapped sulfur as hydrogen sulfide gas. If desired, thereleased hydrogen sulfide can be collected as elemental sulfur usingmethods such as the Claus process. In the Claus process, a portion ofthe H₂S is reacted with oxygen to form SO₂. The SO₂ then reacts with theremaining H₂S to form elemental sulfur and water. The elemental sulfurmay be recycled or sold to the petrochemical industry for additionalrevenue.

Local Oil Reformer Module

In yet another embodiment of the present invention, a portion of thelocal oil may be used as the fuel source for the reforming reaction.This is highly convenient, and under some conditions may be economical.Local, unrefined oil may be significantly cheaper than oil for theend-consumer because no transportation or processing is required.Accordingly, in one embodiment of the present invention, an oil reformermodule is used, in which a portion of the oil extracted from the oilwell is used in a closed-loop system as a reforming fuel source.

FIG. 8 shows a schematic of a system 800 utilizing a catalytic oilreformer module 807. A portion of the petroleum 801 recovered from theoil site is fed into sulfur removal module 803. Desulfurized petroleumis fed via another line into catalytic oil reformer module 807. Steamfrom boiler 805, and optionally oxygen from oxygen tank 804, is added tooil reformer module 807. The exhaust driver gas exiting the oil reformermodule 807 is passed through a set of heat exchangers (not shown). Thecooled driver gas is passed to separator module 809, in which it isseparated into a portion rich in hydrogen gas 811, and a portion rich inCO₂ gas. The CO₂-rich gas portion is sent to compressor module 811. Thecompressor module 811 compresses the CO₂-rich driver gas to a pressureappropriate for the oil well. Finally, the high pressure CO₂-rich drivergas 813 is injected via an injection line into injection well 815. Theoil is recovered using the same injection well 815 (“Huff-and-Puff”) oranother production well 817. After oil recovery 819, a portion of therecovered oil is fed back into sulfur removal module 803, thereforecompleting the closed-loop system. A small portion of the oil recoveredis sacrificed in order to extract a significant amount of oil from theoil well. The hydrogen gas 811 is fed to gas turbine 825, where itgenerates electricity via generator 827, which may be fed to theelectric grid 829 or used on-site. As with the coal reforming modules,heat recovered from the local oil reformer module may be used togenerate electrical or mechanical power to drive the compressor moduleor other system hardware. When using locally produced crude oil in thereformer module, as when using coal or natural gas, sulfur removal maybe necessary, and may be effectuated in a similar manner.

Example of a Modular Design

FIG. 9 shows an example of a modular design 900 that includes one ormore interchangeable modules which may be used. For example, any of anumber of reformer modules may be used. Biomass reformer modules 902 and904, coal reformer modules 906 and 908, are shown for illustrativepurposes only. A local oil reformer module, a methanol reformer module,or any other reformer module according to the present invention may beused in-situ. Any heat exchange module, such as heat exchanger 910, andany gas separator module, such as methanol separator module 912 orsorption bed 914, may be used in-situ. Any power generator module, suchas fuel cells 916 and 918 or gas turbines 920 and 922, may be usedin-situ and fueled off the hydrogen gas 924. Any compressor module, suchas compressor 928, may be used in-situ to compress the CO₂ gas 926. Anygas injection module, such as injection module 930, may be attached tothe compressor module 928. The gas injection module may be a port, ahole, or any interconnecting interface between the compressor module 928and an injection well 934. Driver gas rich in CO₂ 932 exits thecompressor module 928 via injection module 930 and is sent into theinjection well 934.

The modules are placed in-situ and interconnected in the appropriatefashion. They may be transported on a chassis, transported on a truck,boat, plane, or other vehicle, and interconnected on-site. They may betransported together or separately. They may be assembled on-site,either from modular components brought from off-site, or constructed onthe premises of the oil field de-novo.

In FIG. 10, an oil site 1000 (which may be otherwise “depleted”) havinga residual amount of oil is illustrated. The simplest configuration ofthe system, having a reformer module and a compressor module, is shown.An in-situ reformer module 1002 in accordance with the present inventiongenerates driver gas (shown as arrow 1004) that may be pumped into aninjection well 1008 for removing the residual oil 1009 from the oil site1000. As explained herein, the reformer module 1002 may reform or reactfuel sources such as biomass, natural gas, coal, and other likematerials (or mixtures thereof) with (or without) water to form drivergas 1004 which, in one example, is a hydrogen and carbon dioxide gasmixture. The driver gas 1004 is then compressed by a compressor module1006 into high pressure gas that could be pumped underground, viainjection well 1008, where it could impose pressure on residualunderground petroleum 1009 sufficient to allow it to be extracted by thesame oil well, a nearby oil well 1010, or other like site. As shown inFIG. 10, all of the driver gas, including both the carbon dioxide andhydrogen, may be injected into the well for the purposes of oilrecovery. In an alternative embodiment, not shown in FIG. 10 anddescribed next, all or part of the hydrogen may be separated from thecarbon dioxide and, instead of being injected into the oil well, usedfor alternative purposes such as the generation of electric power or thehydrogenation of oil.

FIG. 11 illustrates another example of an embodiment 1100 of the presentinvention for extracting oil from an oil site and for generatingelectricity. This example is illustrative only, and is not intended tolimit the scope of the present invention. Fuel 1102 and water 1104 arefed into reformer module 1106. The fuel and water may also be pre-mixedand fed into reformer 1106 as a single stream. Oxygen, or anotheroxidizing agent, may be added to reformer 1106 via another line (notshown), or pre-mixed with either the fuel, or water, or both. Generateddriver gas, which may include CO₂, H₂, as well as other gases, is fedinto gas separator 1108, which separates a portion of the hydrogen gasfrom the other driver gases. A portion of the separated hydrogen gas isfed into power generator 1110, which could be a gas turbine, to generateelectricity. A portion of the electricity is fed into the electric grid1112. A portion of the electricity may also be used on-site, to providepower to various modules, such as the compressor 1114. The rest of thedriver gas is compressed by compressor 1114 for injection into injectionwell 1116. The driver gases, including the carbon dioxide as well as aportion of the hydrogen gas, and potentially other gases (such as N₂),pressurize the underground petroleum formation 1118 and reduce itsviscosity. Crude oil 1124 is more amenable to recovery by oil recoveryhead 1122 via production well 1120, or other like site.

This is but one system configuration that is possible utilizing themodular components of the present invention, and the present inventionis not limited to this particular configuration. For example, anoperator who does not wish to generate electricity, and/or an operatorwho wishes to use all of the hydrogen gas along with the carbon dioxidegas for enhanced oil recovery, would not use a gas separator module or apower generator module, but would still use a reformer module and acompressor module. As another example, an operator who wishes to operatea hydrogenation plant near the oil well may chose to use a gas separatormodule to separate the hydrogen, but may chose not to use a powergenerator module. Such an operator would still use the other modules,and would feed the hydrogen gas to the hydrogenation plant.

That is, in one embodiment of the present invention, the hydrogen gasmay be separated, and used separately from the carbon dioxide gas. Forexample, the hydrogen gas may be burned in a gas turbine, or sold to thepetrochemical industry for crude oil refinery utilization (notillustrated), or to other parties for other purposes. In an alternativeembodiment of the present invention, the hydrogen may be mixed with thecarbon dioxide, and used in conjunction with the carbon dioxide forenhanced oil recovery.

FIG. 12 illustrates a scenario 1200 where an oil field operator uses abiomass system capable of generating one million cubic feet of CO₂ a day(or 1,000 kcf) and 1,400 kcf of hydrogen. In this scenario, the CO₂ issequestered underground in the field, generating about 100 extra barrelsof crude oil per day while the hydrogen is burned on site to generateemissions-free, distributed electricity which is sold to a local utilitygrid. In the discussion below, the figure illustrates the amount of CO₂sequestered for each barrel of oil produced and clean electricitygenerated.

In FIG. 12, atmospheric CO₂ 1202 is captured by plant matter 1204 duringthe course of the natural carbon cycle. The carbon ends up in the plantmatter biomass 1204, which is harvested for use in the system. About 307kg of biomass 1206, which contains about 138 kg of carbon, is fed intothe power plant 1208 designed according to the principles of the presentinvention. The power plant 1208 generates about 10 kcf of CO₂ 1210,which is used to extract an extra barrel of oil 1222 from an oil field1212. One barrel of oil contains about 120 kg of carbon, out of which,on average, about 103 kg is released as atmospheric CO₂ 1202 when theoil is consumed, completing the carbon cycle. Thus, about 30% morecarbon is sequestered underground than is released when the refined oilproduct is ultimately consumed, for example, in a vehicle driving on ahighway.

Simultaneously, as shown in FIG. 12, hydrogen 1214 is also generated,which is fed to a 1.8 MW gas turbine 1216, which generates cleanelectricity 1218, which can be used for local field operations, or soldto the utility grid 1220. This electricity is carbon-free, since H₂ is aclean-burning fuel and does not release any CO₂ upon combustion in thegas turbine.

Therefore, according to one broad aspect of one embodiment of thepresent invention, both carbon-negative oil and carbon-free electricitymay be generated using the principles of the present invention in aneconomical and financially profitable manner.

Parametric Economic Analysis: Choosing Between Reformer Modules

A parametric economic model was designed to assist an operator inselecting an appropriate fuel reformer. Certain assumptions are inputinto the model (for example, cost of raw materials and capital/operatingexpenses). The model may be used to select among alternative fuelsources, reformer modules, and among other appropriate modules for thesystem.

A sample economic analysis was performed to determine the profitabilityof using the system for enhanced oil recovery in a particular oil fieldunder particular market conditions. The results indicate that theoperation of the system is profitable in this particular scenario if thesystem feeds are coal, natural gas, propane, or local oil. The profitsare directly proportional to the efficacy of H₂ relative to CO₂ atrecovering oil and inversely proportional to the cost of the feedstock.

Several assumptions were made about the unit size, the feedstockmaterials, and the capital and operating expenses when utilizing thepresent invention in this particular hypothetical scenario. Anassumption was made on the unit size of the reformer modules. Thecalculations were based on a modular system, with each reformer moduleproducing 250 kcf (thousand cubic feet) of CO₂ per day of operations.Two scenarios were calculated, one in which a single 250 kcf/dayreformer module is used (FIG. 13) and one in which four such reformermodules are used at a single oil site to produce a gross of 1 MMcf/day(FIG. 14).

The feedstocks included in this analysis were coal, local oil, naturalgas, propane, and methanol. For calculation purposes, natural gas wasassumed to be equivalent to methane and local oil was assumed to haveproperties similar to n-decane. The prices and properties of thereforming and combustion reactions are tabulated in Table 2. The priceincludes a $14 delivery charge to the site. This includes 500 miles byrail at 1.4 ¢/ton-mile and 50 miles by truck at 14 ¢/ton-mile (1ton=2200 lbs.) based on data obtained from the United States Departmentof Energy (DOE). Coal was assumed to have an average cost of $44 per ton(a conservative estimate), local oil was assumed to have an averagevalue of $60/barrel, methane (natural gas) was assumed to have anaverage cost of $6.60/kcf, methanol was assumed to have an average costof $1.65/gallon, and propane was assumed to have an average cost of$1.00/gallon. All pricing data was acquired from the U.S. Department ofEnergy.

Table 2 summarizes the input parameters. Of course, an operator of thepresent invention would adjust these input parameters to fit theappropriate conditions of the oil well that the operator wasconsidering.

TABLE 2 Cost, energy content, and CO₂ and H₂ production quantities ofvarious fuels Reforming per ton fuel Combustion Price energy per tonfuel $/ton (kJ) cf CO₂ cf H₂ energy (kJ) cf CO₂ Coal $44 14.8E+06 70,666141,332 −32.8E+06 70,666 Local oil $469 14.5E+06 58,889 182,556−43.6E+06 69,444 Methane $350 15.4E+06 53,000 212,000 −50.1E+06 62,500Methanol $565 2.0E+06 26,500 53,000 −19.9E+06 26,500 Propane $5448.4E+06 57,818 192,727 −46.4E+06 57,818

The capital and operating expenses were based on four scenariosdepending on the feedstock and whether the H₂ is injected for oilrecovery or separated for electricity production.

It was assumed that the use of coal would require an additional $500,000in capital expenses for the additional processing steps associated withthe coal reformer modules described above. Furthermore, if the H₂ isseparated and converted into electricity, it was assumed that therewould be an additional $500,000 increase in capital expenses for the gasseparator and power generator modules described above. The capitalexpenses were amortized over a period of 10 years. The operatingexpenses were assumed to be slightly higher if coal is used as thefeedstock material considering the ancillary equipment associated withthe coal reformer modules described above. The capital expenses andoperating expenses are summarized in Table 3.

TABLE 3 Capital and operating expenses for various scenarios FeedstockH₂ injected H₂ separated Comment Capital Expenses Coal $1,500,000$2,000,000 amortized over 10 years Capital Expenses Other $1,000,000$1,500,000 amortized over 10 years Operating Expenses Coal $300,000$450,000 per year Operating Expenses Other $200,000 $300,000 per year

It was also assumed that each 10 kcf of CO₂ injected would lead to 1 bblof oil recovered. It was also assumed that hydrogen could be convertedto electricity with 33% efficiency and that the electricity could besold for 100 per kWe-hr ($0.10/kWh, based on data from the U.S.Department of Energy). It should also be noted that the CO₂ producedfrom the combustion reaction was assumed to be separated from the fluegas and injected into the well for oil recovery.

Using the assumptions above, a cost of operating a 250 kcf/day reformermodule with different operating parameters was calculated. Theperformance was calculated with different combinations of fuels for thereforming reaction and the combustion reaction; whether the hydrogen wasinjected into the well or separated for electricity production; and withdifferent efficacies of hydrogen at oil recovery relative to CO₂. Theresults of this analysis are shown in FIG. 13 for a single day ofoperation at a CO₂ output of 250 kcf/day from the reformer moduleSimilarly, results were obtained for an oil field operating four suchreformer modules simultaneously to produce 1,000 kcf CO₂ in a single dayof operation, as shown in FIG. 14. (Note that the financial multiplesimprove with the use of four reformer modules.)

Utilizing the calculated results, financial multipliers may bedetermined as a function of the effectiveness of hydrogen at oilrecovery relative to CO₂. This function is shown for different fuels inFIG. 15. It is clear that the profits increase with the effectiveness ofhydrogen relative to CO₂ for all reformer fuels. Notably, even if thehydrogen does not aid in oil recovery, using coal, methane, or local oilis still profitable with financial multipliers ranging from 1.2 forlocal oil to 2.2 for coal.

The results of FIGS. 13-15 indicate that the financial returns areimpressive, especially when a cheap fuel such as coal is used andhydrogen is at least as effective as CO₂ at oil recovery ($4 to $6return on each dollar invested).

Preliminary laboratory test results, which measured only short-termeffects of hydrogen (that is, its physical, not its chemical effects),show hydrogen to be 25% as effective, on a molecule-for-molecule basis,as CO₂ in reducing oil viscosity. This is a significant finding, becauseas shown by Reactions 4-11, significantly more hydrogen is produced on amolar basis than carbon dioxide. If four times as much hydrogen isproduced as carbon dioxide from steam reforming, and hydrogen is 25% aseffective as CO₂, then the total amount of hydrogen is as effective asthe CO₂ in enhanced oil recovery, and the additional hydrogen increasesthe efficiency of CO₂-EOR by two-fold. Further, the preliminary testresults did not take into account the long-term chemical effects ofhydrogen-petroleum interaction (such as in-situ hydrogenation, forexample), nor the potential cooperative effects of hydrogen and carbondioxide.

Thus it may be seen that carbon dioxide and hydrogen, working alone orin combination, have unique properties that can be applied to theproblems of improved recovery of crude oil.

Other Embodiments

Therefore, according to one broad aspect of one embodiment of thepresent invention, both carbon-negative oil and carbon-free electricitymay be generated using the principles of the present invention in aneconomical and financially profitable manner. In fact, using theprinciples of the present invention, any carbon-intensive industrialprocess can be turned into a low-carbon intensive process, or even acarbon-negative process, by utilizing the principles taught in thepresent invention.

Accordingly, another embodiment of the present invention is ahydrocarbon, which when combusted, releases less carbon dioxide than theamount of carbon dioxide sequestered underground during a process ofextracting the hydrocarbon.

Yet another embodiment of the present invention is a petroleum productextracted by a process comprising the steps of injecting carbon dioxideinto an injection well, and recovering the petroleum product from aproduction well, where an amount of carbon dioxide injected into theinjection well is greater than or equal to an amount of carbon dioxidereleased into the atmosphere when the petroleum product is combusted.

Yet another embodiment of the present invention is a method for removingcarbon dioxide from the atmosphere, and hence helping mitigate globalwarming, the method comprising the steps of: providing a carbonaceousfuel reaction apparatus; providing carbonaceous fuel for thecarbonaceous fuel reaction apparatus; generating carbon dioxide gas fromthe carbonaceous fuel using the carbonaceous fuel reaction apparatus;and utilizing the carbon dioxide gas in a manner that substantially doesnot release the carbon dioxide gas into the atmosphere.

Another embodiment of the present invention is the method above, wherethe carbon dioxide gas is used to grow algae and/or plants ingreenhouses. Yet another embodiment of the present invention is themethod above, where the carbon dioxide is sequestered underground in asaline aquifer, depleted oil field, depleted gas field, and/orunmineable coal seam. Yet another embodiment of the present invention isthe method above, where the carbon dioxide is used for enhanced oilrecovery (EOR), enhanced gas recovery, and/or enhanced coal-bed methanerecovery. Yet another embodiment includes sequestering the CO₂ in theoceans.

In yet another alternative embodiment of the present invention, theprinciples of the present invention may be used to retrofit an existingnatural gas-fired power plant to work with biomass and/or coal, whilereducing CO₂ emissions. Natural gas power plants, especially natural gascombined cycle (NGCC) power plants, are gaining in popularity because oftheir higher efficiencies and less carbon dioxide emissions as comparedto coal-fired power plants. Unfortunately, the price of natural gas ishighly volatile, being coupled to the volatility of petroleum prices.Therefore, it would be advantageous to utilize coal and/or biomass as afeedstock in an NGCC plant without losing the thermal and environmentalefficiencies of an NGCC plant. The principles of the present inventionmay be used to create a high-pressure stream of H₂ and a high pressurestream of CO₂, which may be easily sequestered or beneficially utilized.The H₂ may then be fed into a traditional NGCC power plant, henceretrofitting an existing NGCC power plant to run on coal and/or biomass,which is a fuel significantly cheaper than natural gas and without theprice volatility of natural gas. In addition, the H₂ burns even cleanerthan the original natural gas, and therefore the present invention maybe used to retrofit a natural gas power plant to run on hydrogen, whilesequestering nearly 100% of the CO₂ in the coal and/or biomass used asthe fuel source.

As an alternative to using a reforming reaction to generate highpressure gas, it is an alternative embodiment of the present inventionto use combustion and/or gasification followed by water-gas-shiftreaction to generate the gases, and still be within the spirit and scopeof the present invention. In general, a reforming reaction is preferableto using combustion or gasification using air because either reactionwould produce driver gas mixed with large amounts of nitrogen from air,which is undesirable. As an alternative to using air-blow combustion orgasification, it is another embodiment of the present invention to useoxygen-blown combustion or gasification, and still be within the spiritand scope of the present invention. In general, a reforming reaction isstill preferable to using oxygen-blown combustion or gasification,because in either case, a source of pure oxygen is required, which mustbe separated from air, introducing an additional expense.

INDUSTRIAL APPLICATIONS OF THE PRESENT INVENTION

The worldwide oil industry today faces declining productivity innumerous oil fields that have reached a near-depleted state where thestandard extraction methods can no longer provide profitable results.

A typical oil field goes through three distinct phases:

Phase 1—Primary recovery: The average initial recovery produces about30% of the oil in the reservoir and is accomplished by relying on theexisting underground gas pressure.

Phase 2—Secondary recovery: An additional 10%-30% of the underground oilcan be extracted from the reservoir using such methods as waterflooding. Towards the end of Phase 1 there is a gradual decline in oilrecovery productivity, leading to a transition into Phase 2, whichboosts oil recovery productivity by injecting water to drive the oil outof the reservoir. When Phase 2 nears completion, however, most oilfields cannot transition into Phase 3 because it is not economicallyfeasible to do so.

Phase 3—Enhanced Oil Recovery (EOR): Carbon dioxide (CO₂) gas floodingcan be used in order to extract about 20% more oil from the reservoir,extending the productive life of the field by 10-25 years. When an oilfield's productivity declines towards Phase 3 and enters a certain lowprofitability plateau, it is considered to be “depleted”. At this point,the field may be capped and abandoned or otherwise minimally operated,unless it is able to utilize EOR techniques in a profitable way.

While Phase 1 and Phase 2 are not very complex and yield high profitmargins, Phase 3 poses a problem for literally thousands of oil fieldsin the U.S. alone and many thousands more worldwide.

As discussed above, the major problem with CO₂-EOR is that for most oilfields, CO₂ is not readily available at or near the oil site. This meansthat the CO₂ must be obtained from natural or industrial sources, anddelivered to the oil field over long distances, usually via a pipeline.For most oil fields, a CO₂ pipeline is not a viable option because of amix of several problems, including but not limited to, the capitalinvestment for building a pipeline—sometimes tens of millions ofdollars; the time-frame of building a pipeline—several years; thedistance and terrain issues between the source and destination whicheither make the pipeline impossible or simply not economical; and thetime it takes to start generating an increase in productivity—return oninvestment (ROI) is long.

When faced with the hurdles and overall costs of the pipeline-deliveredCO₂, as described above, the Phase-3 CO₂ EOR simply does not makeeconomical sense for most oil fields. According to several studiesconducted by the U.S. Department of Energy, there are thousands of oilfields in the United States that cannot achieve a financially viableCO₂-EOR production with the currently available CO₂ sources andtechnologies, due to economic and geographic constraints with thecurrent available CO₂ sources and technologies.

For example, one DOE study found that “CO₂ enhanced oil recovery (EOR)is usually only applied when there is an abundant CO₂ source nearby thewell. This is certainly not the case in Kansas where there are hundredsof millions of barrels of oil available that is currently out of reachbecause there is no local source of CO₂.” Oil fields such as the Kansasexample above and many others, including oil fields in Pennsylvania,Ohio, West Virginia, Kentucky, Colorado, Wyoming, California, etc. arepotential places of application for the present invention.

The innovative system produces both carbon dioxide gas (CO₂) andhydrogen gas (H₂) at low cost, specifically tailored to the needs of oilfields that are facing declining productivity and require Enhanced OilRecovery.

The key factors behind the current solution to the EOR challenges are:

-   -   Reforming carbonaceous material and water into CO₂ and hydrogen.        Carbonaceous material, including biomass, is very common, cheap        and commercially available almost anywhere in large quantities,        making it an ideal fuel stock.    -   Overall gas production cost is well below $2 per thousand cubic        feet (kcf) of CO₂—providing a large margin to the DOE's $2/kcf        CO₂ threshold of economic viability.    -   Added value from hydrogen, which may be used either to produce        “green” electricity or for more efficient oil recovery.    -   On-site gas production at the oil field—overcoming the        geographic and financial constraints of delivering CO₂ to the        oil field, eliminating the need for expensive pipelines and        large gas plants.    -   Modular: The system may be modular—allowing use of fuels other        than biomass, when such fuels are naturally available at the oil        field, such as “stranded” natural gas that would otherwise be        flared.    -   Green Electricity: The system produces electricity without        harmful greenhouse gas emissions—proposals are being considered        to create taxes on CO₂ emissions—the system would allow oil to        be recovered without incurring these tax penalties. Further        income could be obtained by selling carbon credits to others.

According to the U.S. Department of Energy, at an oil price of $60/bbl,operators are willing to undertake EOR if CO₂ can be obtained for aprice of $2/kcf.

Hydrogen is valuable in at least three possible ways:

-   -   Hydrogen can be burned to produce electricity.    -   Hydrogen could be effective in extracting oil when injected into        the ground along with the CO₂.    -   Hydrogen can be used in chemical processes to hydrogenate heavy        oils, increasing their value, as well as for other purposes.

Macroeconomic Impact

Above, the impact of the technology on a single user was discussed, toshow that it would be highly profitable. This is the key to thepropagation of the technology to a large number of fields. In thissection, the macroeconomic effect of the technology is discussed once ithas been put into broad use, showing that it could have a major impactin both securing America's oil supply, meeting expanded electricityneeds, and reducing carbon emissions.

The DOE has identified 1100 major oil reservoirs containing collectivelyhundreds of thousands of oil fields that would be amenable to EOR,provided a source of CO₂ were available. Currently, only a tiny fractionof these fields can access CO₂. This system would make CO₂ available toall of them. According to the DOE, EOR currently provides approximately5% of U.S. oil production. Once this system is made available, thisfraction could increase dramatically.

Let us consider: With over 100,000 oilfields needing CO₂ for EOR, it isreasonable to assume that eventually 10,000 units could be put intooperation in the U.S. alone. These would collectively produce 1 millionbarrels of oil per day, an increase on the order of 15% of the Americandomestic oil production. Additional units deployed outside the U.S.would add vast additional petroleum reserves to the world's availableresources, making the fuel supply of all nations more plentiful andsecure. Furthermore, since when using biomass, more CO₂ would besequestered in the process of producing this oil than that released byburning it, the use of such oil would add nothing to global atmosphericCO₂ concentrations. This is very important, because as China, India, andother nations industrialize, there may soon be billions of additionalautomobiles operating around the world. This technology distributedinternationally would allow them to be fueled without driving climatechange.

In addition to providing net carbon emission-free oil, 10,000 Americanunits would also make available 20,000 MW (20 GW) of renewable carbonemission-free electricity, available as desired, around the clock in theU.S. alone. Still more benefits would accrue as the technology isdisseminated internationally.

Thus it can be seen that the deployment of this technology according tothe principles of the present invention will meet the critical goals ofsecuring America's oil and electricity supplies while reducing carbonemissions both here and around the globe.

As shown above, the amount of hydrogen produced by reforming sufficientbiomass to produce 1-10 MMcf/day of carbon dioxide driver gas is alsosufficient to produce about 2-20 Megawatts (MW) of electric power. Thisis a convenient size to feed meaningful amounts of electricity into anelectric power grid to support growth of demand faced by power companiesin a modular fashion, without the need for massive investment in new,large-scale (approximately 250-1000 MW) facilities. Thus, the massproduction and deployment of the present invention could be potentiallyvery attractive to utility companies, allowing them to meet theircustomer's demand for increased supply, without the risk of majorinvestments in large facilities, while receiving their power from aconstant, regularly-available, carbon-emission-free source. This is incontrast to supplementing utility power with wind turbines, solar cells,and the like, whose power, while also carbon-emissions-free, is onlyavailable on an intermittent, irregular basis.

While the methods disclosed herein have been described and shown withreference to particular operations performed in a particular order, itwill be understood that these operations may be combined, sub-divided,or re-ordered to form equivalent methods without departing from theteachings of the present invention. Accordingly, unless specificallyindicated herein, the order and grouping of the operations is not alimitation of the present invention.

While the present invention has been particularly shown and describedwith reference to embodiments thereof, it will be understood by thoseskilled in the art that various other changes in the form and detailsmay be made without departing from the spirit and scope of the presentinvention.

1-20. (canceled)
 21. A method of using an in-situ apparatus forgenerating carbon dioxide gas near an oil site for use in enhanced oilrecovery, comprising: bringing an in-situ apparatus for generatingcarbon dioxide gas to an oil site, the apparatus comprising a steamgenerator adapted to boil and superheat water to generate a source ofsuperheated steam; a source of essentially pure oxygen; a steamreformer, located adjacent to the oil site, adapted to react acarbonaceous material with the superheated steam and the pure oxygen, inan absence of air, to generate a driver gas comprising primarily carbondioxide gas and hydrogen gas, wherein at least a portion of thecarbonaceous material is obtained from a location outside the oil site;and a separator adapted to separate at least a portion of the carbondioxide gas from the driver gas to generate a carbon dioxide-rich drivergas and a hydrogen-rich fuel gas, wherein the separator is amethanol-based separator operating in a temperature-swing cycle betweenapproximately −60° C. and +40° C., or a pressure-swing cycle betweenapproximately 1 bar and 100 bar. providing a source of superheatedsteam; providing a source of essentially pure oxygen; controlling aninput oxygen-to-steam ratio based on a temperature, a pressure, and agas composition of a driver gas in real-time; steam reforming acarbonaceous material with the superheated steam and the pure oxygen togenerate a driver gas comprising primarily carbon dioxide gas andhydrogen gas, wherein the steam reforming reaction is performed adjacentto the oil site and in an absence of air; separating at least a portionof the carbon dioxide gas from the driver gas to generate a carbondioxide-rich driver gas and a hydrogen-rich fuel gas; compressing thecarbon dioxide-rich driver gas for use in enhanced oil recovery; andinjecting the compressed portion of the carbon dioxide-rich driver gas,with substantially no oxygen, to a predetermined depth in order toenhance oil recovery at the oil site.
 22. The method of claim 21,wherein the carbonaceous material is selected from the group consistingof coal, biomass, natural gas, crude petroleum, ethanol, methanol, andtrash.
 23. The method of claim 21, further comprising: generatingelectricity using a portion of the hydrogen-rich fuel gas.
 24. Themethod of claim 21, further comprising: utilizing a water gas-shiftreaction downstream of the steam reforming reaction to convert residualcarbon monoxide in the driver gas into additional carbon dioxide gas andadditional hydrogen gas.
 25. The method of claim 23, wherein theelectricity generated has substantially less associated carbon dioxideemissions than electricity generated from combustion of the carbonaceousmaterial.
 26. The method of claim 21, wherein the driver gas furthercomprises residual carbon monoxide, and wherein the apparatus furthercomprises: a water gas-shift reactor disposed downstream of the steamreformer for converting the residual carbon monoxide into additionalcarbon dioxide gas and additional hydrogen gas.
 27. The method of claim21, wherein the driver gas further comprises residual carbon monoxide,and wherein the apparatus further comprises: a methanation reactordisposed downstream of the steam reformer for converting the residualcarbon monoxide into methane.
 28. The method of claim 21, wherein theapparatus further comprises: a furnace adapted to utilize a portion ofthe hydrogen-rich fuel gas to generate heat necessary to drive the steamreformer.
 29. The method of claim 21, wherein the apparatus furthercomprises: a heat exchanger disposed between the steam generator and thesteam reformer adapted to exchange heat between the hot driver gasexiting the steam reformer and the steam entering the steam reformer.30. The method of claim 29, wherein the apparatus further comprises: acondenser disposed after the heat exchanger adapted to condense and coolthe driver gas before entering the separator.
 31. The method of claim21, wherein the apparatus further comprises: a furnace adapted toutilize a portion of the hydrogen-rich fuel gas to generate a portion ofthe heat necessary to drive the steam reformer.
 32. The method of claim21, wherein the steam reformer operates at a temperature ofapproximately 600° C. to 1000° C.
 33. The method of claim 21, whereinthe steam reformer operates at a pressure of approximately 5 bar to 100bar.
 34. The method of claim 21, wherein the separator is amethanol-based separator operating in a temperature-swing cycle betweenapproximately −60° C. and +40° C., or a pressure-swing cycle betweenapproximately 21 bar and 100 bar.
 35. The method of claim 21, whereinthe steam reformer is selected from the group consisting of a fixed bedreformer, a fluidized bed reformer, and an entrained-flow reformer.